Viscoelastic-surfactant treatment fluids having oxidizer

ABSTRACT

A method and reactive treatment fluid for treating a wellbore for filter cake removal, including providing the reactive treatment fluid having a viscoelastic surfactant (VES) into a wellbore in a subterranean formation and attacking the filter cake via the reactive treatment fluid.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser.No. 63/062,333, filed on Aug. 6, 2020, and U.S. Provisional ApplicationSer. No. 62/955,717, filed on Dec. 31, 2019, the entire contents of bothwhich are incorporated herein by reference in their entirety.

TECHNICAL FIELD

This disclosure relates to treating a wellbore.

BACKGROUND

Drilling fluid aides the drilling of holes into a subterranean formationin the Earth's crust. The holes may be labeled as a borehole or awellbore. The drilling fluid may be called drilling mud. The hole may bedrilled for the exploration or production of crude oil and natural gas.The hole may be drilled for other applications, such as a water well.During the drilling, the drilling fluid may cool and lubricate the drillbit and also carry and remove rock cuttings from the hole. The drillingfluid may provide hydrostatic pressure to prevent or reduce formationfluids from the subterranean formation entering into the hole duringdrilling. Drilling fluids (or treatment fluids more generally) caninclude completion fluids, workover fluids, drill-in fluids, and so on.

Drilling fluids may be mixtures of solid additives present asdiscontinuous phases spread in a liquid continuous phase. The liquidcould be water in the case of the water-based drilling fluids (WBDF) oroil for the oil-based drilling fluids (OBDF). As indicated, the drillingfluids may be designed to achieve different operational objectivesincluding lubrication of the drill bit and drill string, transferringthe drilled cuttings out of the hole while drilling, and suspendingcuttings when the fluid circulation is stopped. Another objective may beto prevent the formation fluids from invading the wellbore hole. In thedrilling operation with the drilling fluid, wellbore stability may bepromoted by forming a low-permeability film on the borehole wall labeledas filter cake (also called cake, mudcake, or wall cake). The filtercake may also reduce drilling fluid invasion into the drilled formation.

SUMMARY

An aspect relates to a method of treating a wellbore for filter cakeremoval, including providing a reactive treatment fluid having aviscoelastic surfactant (VES) into a wellbore in a subterraneanformation to attack filter cake in the wellbore, and attacking thefilter cake via the reactive treatment fluid. As used herein, the filtercake “removal” can include permeability enhancement of the filter cake.

An aspect relates to a reactive treatment fluid for removing filter cakefrom a wellbore in a subterranean formation. The reactive treatmentfluid includes a reactive breaker including an oxidizing salt to breakpolymer in the filter cake. The reactive treatment fluid includes VES togel the reactive treatment fluid to give the reactive treatment fluid asa VES gel (e.g., for retention of the oxidizing salt for breaking thepolymer in the filter cake at an end portion of a lateral of thewellbore). The reactive treatment fluid includes an acid-generatingmaterial to form acid via heat from the subterranean formation or pHtrigger to attack weighting agent from drilling fluid in the filtercake, wherein the acid lowers viscosity of the VES gel.

The details of one or more implementations are set forth in descriptionand in the accompanying drawings. Other features and advantages will beapparent from the description, drawings, and the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of a well including a wellbore formed in ageological formation (subterranean formation) having organic matter,such as kerogen.

FIG. 2 a diagram of the well of FIG. 1 after a hydraulic fracture isformed and with the well in production.

FIG. 3 is a diagram of micellization in which surfactant molecules inaqueous solution form into a colloidal structure that is a surfactantmicelle.

FIG. 4 is a diagram of micelle shapes (types).

FIG. 5 is a diagram of exemplary chemical structures of zwitterionicsurfactants that may be a surfactant in the reactive viscoelasticsurfactant (VES)-based fluid.

FIG. 6 is a diagram of exemplary chemical structures of cationicsurfactants that may be a surfactant in the reactive VES-based fluid.

FIG. 7 is a diagram of exemplary chemical structures of anionicsurfactants that may be a surfactant in the reactive VES-based fluid.

FIG. 8 is a diagram of exemplary chemical structures of nonionicsurfactants that may be a surfactant in the reactive VES-based fluid.

FIG. 9 is a diagram of a well system having a wellbore formed throughthe Earth surface into a geological formation in the Earth crust.

FIG. 10 is a method of hydraulic fracturing a geological formationhaving organic material.

FIG. 11 is Table 1 giving solution parameters for the three VES fluidsamples prepared for viscosity measurement in Example 1.

FIG. 12 is a plot of viscosity and temperature over time for the threeVES fluid samples in Example 1.

FIG. 13 is Table 2 giving solution parameters for the three VES fluidsprepared with the polymer additive FP9515SH for viscosity measurement inExample 2.

FIG. 14 is a plot of viscosity and temperature over time for the threeVES fluid samples in Example 2.

FIG. 15 is a diagram of a well having a filter cake.

FIG. 16 is a sequence schematic of particle buildup of filter cake onthe surface of the face of the subterranean formation in a wellbore.

FIG. 17 is a diagram of a well having a wellbore formed through theEarth surface into a subterranean formation.

FIG. 18 is an image of two filter cakes associated with Example 3.

FIG. 19 is a plot of the filtrate versus time for Example 4.

FIG. 20 is a plot of viscosity over time for Example 5.

FIG. 21 is a plot of viscosity over time for the five fluids given inTable 3 for Example 6.

FIG. 22 is a plot of viscosity over time for the five fluids given inTable 4 for Example 9.

FIG. 23 is a plot of volume of the filtrate collected as the four filtercakes were deposited versus time in Example 10.

FIG. 24 is a plot of volume of the filtrate breakthrough collectedthrough the already-deposited filter cakes versus time given in time inExample 10.

FIG. 25 is a plot of volume of the filtrate collected as the filtercakes were deposited versus time in Example 11.

FIG. 26 is a plot of volume of the filtrate breakthrough collectedthrough the already-deposited filter cakes versus time in Example 11.

FIG. 27 is a plot of volume of the filtrate collected as the filtercakes were deposited versus time in Example 12.

FIG. 28 is a plot of volume of the filtrate breakthrough collectedthrough the already-deposited filter cakes versus time in Example 12.

FIG. 29 is a plot of volume of the filtrate collected as the filtercakes were deposited versus time in Example 13.

FIG. 30 is a plot of volume of the filtrate breakthrough collectedthrough the already-deposited filter cakes versus time in Example 13.

FIG. 31 is a plot of induction time versus concentration of LiBr withNH₄Cl and NaBrO₃ for Example 14.

FIG. 32 is a plot of induction time versus concentration of LiCl withNH₄Cl and NaBrO₃ for Example 14.

FIG. 33 is a plot of induction time versus concentration of LiBr withNH₄MS and NaBrO₃ for Example 14.

FIG. 34 is a plot of induction time versus concentration of LiCl withNH₄MS and NaBrO₃ for Example 14.

DETAILED DESCRIPTION

Some aspects of the present disclosure are directed to treatment fluidsor hydraulic fracturing fluids that are viscoelastic surfactant-basedand bear an oxidizing component(s) (oxidizer). The treatment fluid orhydraulic fracturing fluid includes a viscoelastic surfactant (VES) thatforms micelles to increase viscosity of the treatment fluid or hydraulicfracturing fluid as a VES-based fluid. The increase in viscosity may bebeneficial for conveying of proppant by the VES-based hydraulicfracturing fluid.

A first salt may be added to the VES-based hydraulic fracturing fluid todrive formation of the micelles. The first salt may be, for example, amonovalent or divalent salt. The first salt may also alter the inductiontime leading up to acid formation under certain conditions. A secondsalt (for example, an inorganic oxidizer salt) may be added as anoxidizing component of the VES-based hydraulic fracturing fluid to givea reactive VES-based hydraulic fracturing fluid. This second salt as anoxidizer may provide for attack of organic material (for example,kerogen) in the geological formation treated by the reactive VES-basedhydraulic fracturing fluid. The second salt may also further promoteformation of micelles in the VES-based hydraulic-fracturing fluid. Boththe first salt (monovalent or divalent) and the second salt (oxidizer)are inert to oxidation.

In certain embodiments, the first salt (monovalent or divalent salt) isnot added to the reactive VES-based hydraulic-fracturing fluid. Instead,the second salt (oxidizer) provides for the formation of the micelles.In some embodiments, a polymer may be optionally added to reactiveVES-based hydraulic-fracturing fluid to enhance the increase inviscosity. In implementations, the second salt (and first salt ifincluded) may act as a breaker of the viscosity of the reactiveVES-based hydraulic-fracturing fluid with or without a polymer loading.

In some applications, the VES-based fluid containing oxidative materials(for example, oxidizer salt) may be pumped as a stand-alone hydraulicfracturing treatment to fracture the geological formation and transportproppant. The VES-based fluid containing oxidative materials andproppant may be pumped alternatively with VES-based fluid containingoxidative materials and no proppant as a hybrid treatment. The VES-basedfracturing fluid may be pumped as part of a channel fracturingoperation. Channel fracturing may refer to hydraulic fracturingtreatment employing intermittent pumping of proppant-laden fluid andproppant-free fluid to generate conductive channels within theformation.

In other embodiments, the VES-based fluid containing oxidative materialsis pumped alternatively with carbon dioxide (CO₂)-based fluids thatoptionally contain oxidizers for breaking down kerogen. A benefit may bethat CO₂ slugs can enhance the delivery of oxidizer to the kerogen andbetter expel hydrocarbons from the geological formation. If employed,the CO₂-based fluid with oxidizer may contain organic oxidizers,reactive gases, or in-situ forming halogens, or any combinations ofthese. The CO₂-based fluid with oxidizer may be foamed in someinstances.

The VES-based hydraulic-fracturing fluid may be pre-mixed, for example,in a batch mix vessel and then pumped downhole through a wellbore in ageological formation for the hydraulic fracturing of the geologicalformation. The amount of components (for example, surfactant or oxidizersalt) added to the mix vessel (for example, a batch mix vessel (may beadjusted in response to the hydraulic-fracturing conditions and theamount of kerogen or other organic matter in the subterranean region ofthe geological formation being treated. In certain embodiments, at leastsome of the surfactant or oxidizer salt is added to a conduit on thedischarge of the pump conveying the VES-based hydraulic-fracturingfluid. The amount of the oxidizer salt added to the conduit (or to themix vessel) may be adjusted (for example, in real time) in response tothe hydraulic-fracturing conditions and the amount of kerogen or otherorganic matter in the fractures of the geological formation.

It should be understood that the phrase “VES fluid” as utilized in thepresent disclosure generally refers to a “VES-based fluid” in that thefluid contains more than a VES. Similarly, the phrase “VES hydraulicfracturing fluid” generally refers to a VES-based hydraulic fracturingfluid” in that the hydraulic fracturing fluid contains more than a VES.Further, a VES-based fluid having the VES may include water as a basefluid.

While the present discussion initially may at times focus on theVES-based fluid as a VES-based hydraulic fracturing fluid, the presentVES-based fluid may also be a VES-based treatment fluid for treatmentsother than hydraulic fracturing. The other treatments may be independent(or separate) from hydraulic fracturing or in combination with hydraulicfracturing. Implementations of treatments with the VES-based treatmentfluid include: (1) degradation of filter cake during openhole drillingor during hydraulic fracturing; (2) upgrading oil in the subterraneanformation (geological formation) by reducing the viscosity and boilingpoint of the oil; (3) breaking organic matter (for example, paraffin,bitumen, or oil) in the subterranean formation by reducing the viscosityof the organic matter; and (4) oxidizing organic scale (buildup) in asubterranean formation to remove (clean-up) the organic scale to promotesubsequent fluid injection into the subterranean formation for thewellbore employed in an injection well.

Production from unconventional source-rock formations has becomeeconomically viable. The technology for accessing these reservoirscontinues to advance as the industry improves drilling, completion, andstimulation techniques. Unconventional source-rock reservoirs differfrom conventional reservoirs at least due to the presence of thehydrocarbon source material, such as kerogen and kerogen-producedcomponents, in unconventional source-rock reservoirs. This hydrocarbonsource material as irregular organic matter can represent 5-10 weightpercent (wt %) [or 10-20 volume percent (vol %)] of the sedimentarysource-rock formation. An assortment of minerals are woven and compactedtogether with the organic matter (for example, kerogen) resulting in acomplex hierarchical structure with toughness and strengthcharacteristics similar to other natural materials. The tensilecharacteristics of the organic matter have been demonstrated bynanoindentation of organic-rich shale micro/nano-cantilever source-shalebeams tested under a scanning electron microscope (SEM). Thechemomechanical characteristics of the organic matter implicate aproblematic role of the organic matter in the tensile stresses inhydraulic fracturing and in overall mechanical and chemical operationalsuccess of the fracturing. The interwoven organic matter that thefracturing fluid encounters as the fracture extends into the source rockformation is further discussed with respect to FIG. 1.

FIG. 1 is well 100 having a wellbore 102 formed in a geologicalformation 104 having organic matter 106 (organic material), such askerogen. The wellbore 102 is depicted as a circular cross section. Thegeological formation 104 is a subterranean formation in the Earth'scrust and may be an unconventional source-rock formation havinghydrocarbon. The geological formation 104 may be an organic-rich shalezone. The spider-web symbol represents the presence of the organicmatter 106.

In FIG. 1, a fracture 108 is being formed via injection of a fracturingfluid 110 (stimulation fluid) from the Earth's surface through thewellbore 102 into the geological formation 104. The fracturing fluid 110may be injected at a specified flow rate (q₀). The flow rate (q₀) may bespecified as a volumetric flow rate or mass flow rate. The fracturingfluid 110 may include proppant 112, such as sand or ceramic proppant.The fracture 108 may propagate perpendicular to a minimum principalstress 114 of the formation 104 and in a direction against a maximumprincipal stress 116 of the formation.

The schematic in FIG. 1 depicts the hydraulic fracture 108 extendingfrom the wellbore 102. The fracturing fluid 110 system encounters theductile organic matter 106 illustrated as spider webs. The presence ofthe organic matter 106 at the fracture face 118 may restrict thegeneration of permeable channels from the geological formation 104 intothe fracture 108. Thus, the organic matter 106 may inhibit thesubsequent production of hydrocarbon from the formation 104 into andthrough the fracture 108 to the wellbore 102 and Earth surface. Thefracture face 118 may be an interface of the forming fracture 108 withthe geological formation 104. Conventional hydraulic-fracturingstimulation fluids typically do not address challenges of fracturingorganic-rich shale zones. The polymer-like organic material 106 may beintertwined within the organic material and with the rock. The organicmaterial 106 affects fracturing (fracture) behavior and reducesresulting hydraulic conductivity.

Hydraulic fracturing fluids may include polymers or crosslinkers forviscosifying the fracturing fluids as proppant-carrying fluids.Developments in fracturing fluids (or stimulation fluid chemicals) havealso included additives, such as polymer breakers, biocides, clayswelling inhibitors, and scale inhibitors. VES-based hydraulicfracturing fluids may be a cleaner alternative to polymer-based systems.

Among the most commonly-used fracturing fluids for unconventionalformations are slickwater systems incorporating friction-reducingsynthetic polymer that facilitates the pumping of stimulation fluids atlarge rates (for example, at least 100 barrels per minute). Moreover,the incorporation of gas into fracturing fluids may reduce water as acomponent of the fracturing fluid.

To address the challenge of improving hydraulic fracturing inunconventional source-rock reservoirs, embodiments of the presenttechniques include reactive fluids that can break down the polymernature of the organic matter 106 on the hydraulic fracture faces 118. Atthe fracture face 118, organic matter 106 (for example, kerogen) isbeneficially cracked open due to exposure to oxidizing conditions (forexample, aqueous oxidizing conditions). Techniques to implement theoxidizing conditions via a fracturing fluid 110 include, for example:(1) inorganic oxidizers in aqueous fluids, (2) inorganic and organicoxidizers in carbon dioxide (CO₂), (3) inorganic or organic oxidizers infoamed mixtures of water and CO₂, and (4) reactive gases in CO₂.

FIG. 2 is a well 200 that is the well 100 of FIG. 1 after the hydraulicfracture 108 is formed and with the well 200 in production. FIG. 2depicts the hydraulic fracture 108 extending from the wellbore 102. Thefracture 108 has a length 202 and width 204. The fracturing fluid 110(FIG. 1) that formed the fracture 108 was a VES fracturing fluid havingan oxidizer that attacked the organic matter 106. Thus, the fracturingfluid 110 system caused organic matter 106 to crack open to generatepermeable channels from the formation 104 into the fracture 108 andtherefore provide for conductivity from the formation 104 through thefracture 108 to the wellbore 102. The well 200 as depicted is inproduction phase with produced hydrocarbon 206 flow from the geologicalformation 104 through the fracture 108 and wellbore 102 to the Earthsurface. The flow rate of the produced hydrocarbon 206 may be labeled asQ₀ and may be a characterized as a volumetric flow rate or mass flowrate.

As discussed, VES-based systems may be combined with reactive fluidcomponents for breaking down organic matter 106, such as kerogen, in thegeological formation 104. This fracturing-fluid system may also beutilized to upgrade heavy oil or clean-up organic residues.

VES-based fluids generally differ from conventional polymer-basedfracturing fluid systems. Polymer-based fracturing fluids typicallyincorporate a water-soluble polymer, crosslinker, and breaker. A viscouspolymer-based fluid (for example, a gel at greater than 10 centipoise[cP]) is pumped into a geological formation and with the fluid geltransporting proppant into a fracture network. Then, the gel is brokenby enzyme or oxidizer and the fluid flowed back from the formation tothe surface. This process may be operationally complex in relying onpolymer hydration and a variety of additives, such as biocides,crosslinkers, and breakers. By contrast, viscoelastic surfactants may besimpler to utilize in the field because typically there is no hydrationstep and because fewer additives may be included. For example, in thecase of breakers, VES-based fluids can break in the formation by changesin brine concentration due to contact with produced fluids oralternatively by contact with hydrocarbons which disrupt the surfactantmicelles of the VES-based fluid.

An advantage of VES-based fluids over polymer-based systems can be thatVES-based fluids may typically be solids-free (except for any proppant).Therefore, in implementations, the VES-based fluids generally do notdeposit residue in the geological formation or on the proppant pack.Thus, VES-based fluids may be more efficient than polymer-based systemsin hydraulic-fracture reservoir stimulation because the conductivity ofthe in-place proppant pack affects well productivity.

In addition, VES-based fluids may heal after exposure to shear.Additives may further improve the shear re-healing time of the VES-basedfluid gel. A benefit of healing may be that viscosity is maintained forconveying proppant. The self-healing may restore the micelles and hencethe viscosity. The VES fluid experiences shear forces during pumping atthe wellhead. The viscosity may be restored as the VES fluid goes intothe wellbore and formation and thus perform hydraulic fracturing andconvey proppant. Crosslinked polymer fluids, by contrast, can beirreversibly damaged during pumping because the shear forces cause someof the covalent bonds to break. The micelles of the VES fluid are notcovalently held together and their formation is reversible. This may bean advantage of VES over crosslinked polymer for hydraulic fracturing.

Embodiments employ VES gels to hydraulically fracture unconventionalsource-rock formations. These gels may contain a specified amount ofoxidizer that can break down organic material (for example, kerogen) inthe subterranean formation. Thus, embodiments may combine the benefitsof viscoelastic surfactants as fracturing fluids with the reactivecapabilities of an oxidizer component to break down kerogen on thesurface of the fractures. The reactive VES fluid may also be utilized toupgrade heavy oil (for example, bitumen or including bitumen) bybreaking down the heavy oil and reducing viscosity of the heavy oil.Heavy oil may be crude oil having an American Petroleum Institute (API)gravity less than 20°. The reactive VES fluid may also be utilized toclean downhole by removing organic residues from the surface of the rockformation deposited as a result of drilling, completion, and fracturing.The reactive VES fluid may dissolve filter cake in open-hole completions(both water injectors and hydrocarbon producers).

A purpose of the viscoelastic surfactant (for example, cationic,anionic, nonionic, zwitterionic or amphoteric, or a combination ofcationic and anionic surfactants) is to form micelles to increaseviscosity of the fluid to give the VES-based fluid. Cylindrical(truncated) or wormlike micelles give greater fluid viscosity thanspherical micelles. Spherical micelles generally do not produceviscosity. Truncated cylindrical micelles may make worm-like or rod-likemicelles that entangle to give viscosity. VES-based systems may includea surfactant capable of forming a wormlike micelle that can entangle andthus impart viscosity to the fluid. The fluid system typically includessalt to drive formation of the micelles, such as worm-like micelles thatentangle. VES-based fluids may also contain a breaker to disrupt themicelles and reduce the viscosity while in the formation to enhanceflowback.

Surfactant selection may be an aspect of formulating a VES-basedfracturing fluid. Under certain conditions, surfactant molecules arrangeinto colloidal structures called micelles as indicated earlier. Withthese structures, the hydrocarbon tails of the surfactants orient towardeach other while the polar head groups form an interface with thesurrounding aqueous media.

FIG. 3 depicts micellization 300 in which surfactant molecules 302 inaqueous solution form into a colloidal structure that is a surfactantmicelle 306. The surfactant molecules 302 are a hydrocarbon chain havinga polar head group 308 and a hydrocarbon tail 310. Surfactant micelles306 form 304 spontaneously in aqueous solution when the surfactantconcentration, c, exceeds the threshold referred to as the criticalmicelle concentration (cmc). The size and structure of the micelles 306may be controlled by the selected charge and geometry of the surfactantmolecules 302. The size and structure of the micelles 306 may becontrolled by solution conditions, such as concentration of thesurfactant molecules, type and concentration of salt, temperature, ionicstrength, and shear rate.

FIG. 4 gives examples 400 of micelle shapes (types). Depicted are aspherical micelle 402, a cylindrical (worm-like) micelle 404, a vesicles(bilayer) micelle 406, and a lamellar micelle 408. For each micelletype, the respective qualitative prediction of shape may be based on thepacking parameter.

The molecular packing parameter may provide for insight into theself-assembly phenomenon of the surfactant micelle as an aggregate. Themolecular packing parameter is defined as v_(o)/aI_(o), where v_(o) andI_(o) are the volume and the length of the surfactant tail and a is thesurface area of the hydrophobic core of the aggregate expressed permolecule in the aggregate (here referred to as the area per molecule).For instance, for a spherical micelle with a core radius R, made up of gmolecules, the volume of the core V=gv_(o)=4πR³/3 and the surface areaof the core A=ga=4πR². Hence, R=3v_(o)/a from simple geometricalrelations. If the micelle core is packed with surfactant tails withoutempty space, then the radius R cannot exceed the extended length I_(o)of the tail. Introducing this constraint in the expression for R gives0≤v_(o)/aI_(o)≤⅓, for spherical micelles.

For spherical, cylindrical, or bilayer aggregates made up of gsurfactant molecules, the geometrical relations for the volume V and thesurface area A are given in Table 1. The variables V, A, and g in thetable refer to the entire spherical aggregate, unit length of acylindrical aggregate, or unit area of a bilayer aggregate,respectively, for the three shapes. These geometrical relations togetherwith the constraint that at least one dimension of the aggregate (theradius of the sphere or the cylinder, or the half-bilayer thickness, alldenoted by R) cannot exceed I_(o) lead to the following connectionbetween the molecular packing parameter and the aggregate shape:0≤v_(o)/aI_(o)≤⅓ for sphere, ⅓≤v_(o)/aI_(o)≤½ for cylinder, and½≤v_(o)/aI_(o)≤1 for bilayer. Therefore, if the molecular packingparameter is known, the shape and size of the equilibrium aggregate canbe readily identified. This is the predictive sense of the molecularpacking parameter.

TABLE 1 Geometrical Relations for Spherical, Cylindrical, and BilayerAggregates Variable Sphere Cylinder Bilayer volume of core V = gv_(o)4πR³/3 πR² 2R surface area of core A = ga 4πR² 2πR 2 area per molecule a3v_(o)/R 2v_(o)/R v_(o)/R packing parameter v_(o)/a/_(o) v_(o)/a/_(o) ≤⅓ v_(o)/a/_(o) ≤ 1/2 v_(o)/a/_(o) ≤ 1 largest aggregation number g_(max)4π/_(o) ³/3v_(o) π/_(o) ²/v_(o) 2/_(o)/v_(o) aggregation number gg_(max) (3v_(o)/a/_(o))³ g_(max) (2v_(o)/a/_(o))² g_(max)(v_(o)/a/_(o))

Variables V, A, g, and g_(max) refer to the entire spherical aggregate,unit length of a cylinder or unit area of a bilayer. R is the radius ofspherical or cylindrical micelle or the half-bilayer thickness of thespherical vesicle. v_(o) and I_(o) are the volume and extended length ofthe surfactant tail. The variable g_(max) is the largest aggregationnumber possible for the given geometry based on the constraint that theaggregate core is filled and the tail cannot stretch beyond its extendedlength.

Changes to the surfactant molecule or solution conditions influence themicelle structure. Surfactant molecules with polar head groups that arelarge (for example, greater than 8 carbons) may promote the formation ofspherical micelles. Surfactant molecules with polar head groups that aresmall (for example, less than 8 carbons) should encourage lamellaeformation. For instance, nonionic surfactants with small ethylene-oxidehead groups (small number of carbons, m<8) should favor bilayer andlamellae structures. However, nonionic surfactants with larger headgroups (for example, m=10, 12, 14, or 16) may yield cylindrical orwormlike micelles. Further, salt addition to ionic surfactant solutionsgenerally causes a transition from spherical to cylindrical micelles.For example, the cationic surfactant hexadecyltrimethylammonium bromide(also referred to as cetyltrimethylammonium bromide or CTAB) formsspherical micelles in aqueous solution. Upon addition of sodium nitrate(NaNO₃) to the surfactant solution, the spherical micelles transforminto wormlike micelles.

In addition to surfactant selection, formulation of the presentVES-based fracturing fluid may further include salt selection, oxidizerselection, and selection of any polymer loading. The salts utilized mayinteract electrostatically with the polar head groups and thereby reducehead group repulsion. This may cause a structural change to the micelleto ideally form wormlike micelles that can entangle with one another andcause the viscosity of the VES-based fracturing fluid to increase. Awide range of salts are capable of interacting in this manner. Thesesalts can include monovalent or divalent salts. Salts that that areinert to oxidation may be desired.

As for oxidizer selection, the oxidizers employed in this applicationshould demonstrate reactivity toward kerogen. To this end, salts ofchlorate and bromate are examples. Both are reactive toward kerogen.Further, both alkali and alkaline earth metal salts are suitable. Theoxidizers employed should be nonreactive towards the surfactantmolecules in the fracturing fluid at ambient and reservoir temperaturesfor the time period of pumping so that the fluid can maintain viscositythroughout the pumping time. Alternatively, oxidizers may be selectedthat are instead (or also) reactive towards heavy oil or organicresidues in the formation so that this reactive VES fluid could beutilized for upgrading oil or well cleanup.

With respect to polymer loading, polymers are commonly used in hydraulicfracturing fluids to create viscosity. However, such polymers are knownto damage the formation. A traditional VES fluid is advantageous in itslack of polymer additives. This makes VES fluids less damaging to theformation. However, in present embodiments, the oxidizing salt in thereactive VES fluid gives the fluid the capacity to “break” including tobreak polymers in the VES fluid. Thus, in certain implementations,polymer can be added to the reactive VES fluid to boost viscosity of theVES fluid and increase efficacy of the fracturing operation withoutinflicting damage to the formation. The polymer added may include, forexample, acrylamide acrylic acidic copolymer, polyvinyl pyrrolidone,polyethylene oxides, and natural polymers. The acrylamide acrylic acidiccopolymer may be 2-acrylamido-2-methylpropane sulfonic acid (AMPS).Natural polymers added may include guar, xanthan gum, and cellulose.

Embodiments of the reactive VES-based fluid for hydraulic fracturinginclude water and surfactant to form the VES-based fluid. The majority(>90 volume %) of the fluid is water. The amount of VES used for thefluid can range 4-8 volume % depending on the temperature and viscosityrequirement. The hydraulic fracturing fluid as a reactive VES-basedfluid includes an inorganic oxidizer salt. The inorganic oxidizer saltis included as an oxidizer or reactive component for the reactiveVES-based fluid to attack organic matter in the subterranean formation.The inorganic oxidizer salt may also promote micelle formation forincreased viscosity of the reactive VES fluid. The VES-based fluid mayadditionally include a monovalent or divalent salt that promotes micelleformation and is generally not an oxidizer. The monovalent or divalentsalt may additionally alter the induction time prior to acid formation.The reactive VES-based fluid may include organic compounds, such asphthalic acid, salicylic acid, or their salts. Other fluid additives inthe reactive VES-based fluid may include a breaker, corrosion inhibitor,scale inhibitor, biocide, or pH buffer, or any combinations of these.The reactive VES-based fluid may include inorganic oxidizer salt as thesole salt to promote micelle formation and not include the monovalentsalt or divalent salt.

The reactive VES-based fluid (hydraulic fracturing fluid) may have aconcentration of the surfactant, for example, in a range of 0.1 weightpercent (wt %) to 10 wt % or in a range of 0.5 wt % to 7 wt %, or atleast 1 wt %. The surfactant may be, for example, a zwitterionic oramphoteric surfactant, a cationic surfactant, an anionic surfactant, anonionic surfactant, or a combination of cationic and anionicsurfactants.

The zwitterionic surfactant may be a betaine, phosphobetaine, orsultaines. The zwitterionic surfactant may include dihydroxyl alkylglycinate, alkyl ampho acetate or propionate, alkyl amidoamine oxide,gemini VES, alkyl betaine, alkyl amidopropyl betaine, and alkyliminomono- or di-propionates derived from waxes, fats, or oils.

FIG. 5 depicts exemplary structures 500 of a zwitterionic surfactantthat may be the surfactant in the reactive VES-based fluid. Thesestructures 500 include disodium tallowiminodipropionate 502, disodiumoleamidopropyl betaine 504, and erucylamidopropyl betaine 506. For thetallowiminodipropionate 502, R=tallow.

FIG. 6 depicts specific structures 600 of a cationic surfactant that maybe the surfactant in the reactive VES-based fluid. These exemplarystructures 600 for the cationic surfactant are alkylammonium salts andinclude oleyl methyl bis(2-hydroxyethyl)ammonium chloride 602, erucylbis(2-hydroxylethyl)methylammonium chloride 604, and N,N,N,trimethyl-1-octadecammonium chloride 604. Other alkylammonium salts asthe cationic surfactant may include, for example, cetyltrimethylammoniumbromide (CTAB) or dimethylene-1,2-bis(dodecyldimethylammonium bromide).The cationic surfactant can be associated with inorganic anions, such assulfate, nitrate, and halide. The cationic surfactant can be associatedwith organic anions, such as salicylate, functionalized sulfonates,chlorobenzoates, phenates, picolinates, and acetates. The cationicsurfactant can alternatively be associated with an oxidizing anion, suchas chlorate, bromate, perchlorate, chlorite, hypochlorite, persulfate,iodate, bromite, hypobromite, perborate, dichromate, permanganate,ferrate, percarbonate, nitrite, and nitrate.

Anionic surfactants for the reactive VES-based hydraulic fracturingfluid may include alkyl sarcosinates or sulfonates. FIG. 7 givesexemplary structures 700 of anionic surfactants that may be thesurfactant in the VES hydraulic fracturing fluid. Oleoyl sarcosine 702is an example of an alkyl sarcosinate. In implementations, the oleoylsarcosine 702 may constitute about 94% of the sarcosinate product thatis the surfactant. Methyl ester sulfonate 704 and sodium xylenesulfonate 704 are examples of sulfonates. For the methyl ester sulfonate704 structure, R is an alkyl chain with 10-30 carbon atoms,

Nonionic surfactants for the reactive VES-based hydraulic fracturingfluid may include amine oxides. Referring to FIG. 8, the amine oxidegelling agents have the structure 800 where R is an alkyl or alkylamidogroup averaging from about 8 to 27 carbon atoms and each R′ isindependently H, or an alkyl group averaging from about 1 to 6 carbonatoms. In implementations, R is an alkyl or alkylamido group averagingfrom about 8 to 16 carbon atoms and R′ are independently alkyl groupsaveraging from about 2 to 3 carbon atoms. In a particularimplementation, the amino oxide gelling agent is tallow amidopropylamine oxide (TAPAO). Major components of the tallow amidosubstituent are palmitic acid 802, stearic acid 804, and oleic acid 806.

The reactive VES hydraulic fracturing fluid may include monovalent ordivalent salts at a concentration in a range of 0 wt % to 50 wt %, in arange of 1 wt % to 50 wt %, in a range of 0 wt % to 15 wt %, in a rangeof 1 wt % to 15 wt %, or less than 15 wt %. These salts may promotemicelle formation, such as wormlike or cylindrical micelles, to increaseviscosity of the fracturing fluid. These monovalent or divalent saltsmay include lithium fluoride (LiF), sodium fluoride (NaF), potassiumfluoride (KF), magnesium fluoride (MgF₂), calcium fluoride (CaF₂),strontium fluoride (SrF₂), barium fluoride (BaF₂), lithium chloride(LiCl), sodium chloride (NaCl), potassium chloride (KCl), magnesiumchloride (MgCl₂), calcium chloride (CaCl₂), strontium chloride (SrCl₂),barium chloride (BaCl₂), lithium bromide (LiBr), sodium bromide (NaBr),potassium bromide (KBr), magnesium bromide (MgBr₂), calcium bromide(CaBr₂), strontium bromide (SrBr₂), and barium bromide (BaBr₂). Certainsalts, such as LiBr salts, may be particularly beneficial for delayingthe oxidation of ammonium by bromate and, hence, delaying the formationof acid. This may useful for filter cake cleanup where it is desirableto place the VES-based fluid before it starts to react with the filtercake.

The reactive VES hydraulic fracturing fluid includes inorganic oxidizersalts in concentrations in a range of 1 wt % to 20 wt % or in a range of1 wt % to 10 wt %. The concentration may generally be more including atthe greater end of these ranges or greater (for example, 3 wt % to 20 wt% or 5 wt % to 25 wt %) for implementations where other salt (forexample, a monovalent or divalent salt) is not included in theformulation for micelle formation. These inorganic oxidizer salts are anoxidizer or reactive component for the VES hydraulic fracturing fluid toattack and degrade organic material in the geological formation. Theinorganic oxidizer salts are generally inert to oxidation. The oxidizersalts may include lithium chlorate (LiClO₃), sodium chlorate (NaClO₃),potassium chlorate (KClO₃), magnesium chlorate [Mg(ClO₃)₂], calciumchlorate [Ca(ClO₃)₂], strontium chlorate [Sr(ClO₃)₂], barium chlorate[Ba(ClO₃)₂], lithium bromate (LiBrO₃), sodium bromate (NaBrO₃),potassium bromate (KBrO₃), magnesium bromate [Mg(BrO₃)₂], calciumbromate [Ca(BrO₃)₂], strontium bromate [Sr(BrO₃)₂], and barium bromate[Ba(BrO₃)₂]. Other oxidizers may include magnesium peroxide, calciumperoxide, sodium nitrate, sodium nitrite, sodium persulfate, potassiumpersulfate, sodium tetraborate, sodium percarbonate, sodiumhypochlorite, an iodate salt, a periodate salt, a dichromate salt, achlorite salt, a hypochlorite salt, and a permanganate salt. The iodatesalt may be a salt of IO₃ ⁻ with lithium, sodium, potassium, magnesium,etc. Hydrogen peroxide as an oxidizer may also be used.

The inorganic oxidizer salts may promote formation of micelles, such ascylindrical or worm-like micelles, to increase viscosity of thefracturing fluid. Thus, both the inorganic oxidizer salt and theaforementioned monovalent or divalent salt may promote micelleformation. The combined concentration of the inorganic oxidizer salt andthe monovalent or divalent salt in the VES hydraulic fracturing fluidmay be at least 1 wt %, at least 3 wt %, at least 5 wt %, at least 7 wt%, at least 10 wt %, or at least 12 wt %, or at least 15 wt %. Forimplementations where a monovalent or divalent salt is not included inthe formulation, the concentration of the inorganic oxidizer salt in thereactive VES hydraulic fracturing fluid may be at least 3 wt %, at least5 wt %, at least 7 wt %, or at least 10 wt %. These concentrations ofthe inorganic oxidizer may also be employed with the presence of amonovalent or divalent salt.

As mentioned, the reactive VES-based fluid may include organiccompounds, such as phthalic acid, salicylic acid, or their salts. Thesalicylate or other ion in the presence of the surfactant may cause theviscoelastic gel to form. The acid (nonionic) form of these compoundscauses the viscoelasticity development to be delayed until the pH isaltered (raised) and the anion is released. For example, the pH may beraised by adding urea that is hydrolyzed as the solution starts to heatafter pumping into the wellbore and formation. This is a way ofimparting some control over when the viscoelasticity develops. In somecases, carboxylic acid and the —OH group in salicylic acid interactswith the quaternary ammonium group of VES and acts as a crosslinker tolink and make the micelles more robust. This aids formation of stablemicelles and thus stable viscosity at formation temperatures. As alsomentioned, other fluid additives in the reactive VES-based fluid mayinclude a breaker, corrosion inhibitor, scale inhibitor, biocide, or pHbuffer, or any combinations of these.

FIG. 9 is a well site 900 having a wellbore 902 formed through theEarth's surface 904 into a geological formation 906 in the Earth'scrust. The geological formation 906 may be labeled as a subterraneanformation, a rock formation, or a hydrocarbon formation. The geologicalformation 906 may be an unconventional formation to be subjected tohydraulic fracturing.

The wellbore 902 can be vertical, horizontal, or deviated. The wellbore902 can be openhole but is generally a cased wellbore. The annulusbetween the casing and the formation 906 may be cemented. Perforationsmay be formed through the casing and cement into the formation 906. Theperforations may allow both for flow of fracturing fluid into thegeological formation 906 and for flow of produced hydrocarbon from thegeological formation 906 into the wellbore 902.

The well site 900 may have a hydraulic fracturing system including asource 908 of fracturing fluid 910 at the Earth surface 904 near oradjacent the wellbore 902. The source 108 may include one or morevessels holding the fracturing fluid 910. The fracturing fluid 110 maybe stored in vessels or containers on ground, on a vehicle (for example,truck or trailer), or skid-mounted. The fracturing fluid 910 may be awater-based fracturing fluid. In some implementations, the fracturingfluid 910 is slickwater that may be primarily water (for example, atleast 98.5% water by volume). The fracturing fluid 910 can be preparedfrom seawater. The fracturing fluid 910 can also be gel-based fluids.The fracturing fluid 910 can include polymers and surfactants. Otheradditives to the fracturing fluid 910 may include hydrochloric acid,friction reducer, emulsion breaker, emulsifier, temperature stabilizer,and crosslinker. Fracturing fluids 910 of differing viscosity may beemployed in the hydraulic fracturing. The fracturing fluid 910 mayinclude proppant. In the illustrated embodiment, the fracturing fluid910 is a reactive VES-based fracturing fluid for at least a portion ofthe hydraulic fracturing operation.

The hydraulic fracturing system at the well site 900 may include motivedevices such as one or more pumps 912 to pump (inject) the fracturingfluid 910 through the wellbore 902 into the geological formation 906.The pumps 912 may be, for example, positive displacement pumps andarranged in series or parallel. Again, the wellbore 902 may be acemented cased wellbore and have perforations for the fracturing fluid910 to flow (injected) into the formation 906. In some implementations,the speed of the pumps 910 may be controlled to give desired flow rateof the fracturing fluid 910. The system may include a control componentto modulate or maintain the flow of fracturing fluid 910 into thewellbore 902 for the hydraulic fracturing. The control component may be,for example, a control valve(s). In some implementations, as indicated,the control component may be the pump(s) 912 as a metering pump in whichspeed of the pump 912 is controlled to give the desired or specifiedflow rate of the fracturing fluid 910. The set point of the controlcomponent may be manually set or driven by a control system, such as thecontrol system 914.

The fracturing fluid 910 may be prepared (formulated and mixed) offsiteprior to disposition of the fracturing fluid 910 into the source 908vessel at the well site 900. Alternatively, a portion (some components)of the fracturing fluid 910 may be mixed offsite and disposed into thesource 908 vessel and the remaining portion (remaining components) ofthe fracturing fluid 910 added to the source 908 vessel or to a conduitconveying the fracturing fluid 910. In other implementations, thefracturing fluid 908 may be prepared onsite with components added to(and batch mixed in) the source 908 vessel.

For embodiments of the fracturing fluid 910 as a reactive VES-basedfracturing fluid, the fracturing fluid 910 in the source 908 vessel mayhave all components of the fracturing fluid 910. In certain embodiments,some components of the fracturing fluid 910 may be added to the source908 vessel near or at the time (or during) the pumping of the fracturingfluid 910 into the wellbore 902 for the hydraulic fracturing. However,in other embodiments, not all components of the fracturing fluid 910 areinclude in the source 908 vessel. Instead, at least one component of thefracturing fluid 910 is be added to the conduit conveying the fracturingfluid 910 either on the suction of the pump 912 or discharge of the pump912, or both, as the fracturing fluid 910 is being pumped into thewellbore 902.

An additive or component 916 may be added to the fracturing fluid 908.For the reactive VES-based fracturing fluid, the component 916 may be,for example, surfactant or the inorganic oxidizer salt. Theconcentration of the component 916 (for example, inorganic oxidizersalt) in the fracturing fluid 910 may be maintained or adjusted bymodulating a flow rate (mass or volume) of addition of the component 916via a control device 918. The set point of the control device 918 may bemanually set or specified (directed) by the control system 914. Thecontrol device 918 may be a control valve on the conduit conveyingcomponent 916 to the source 908 (for example, vessel) of the fracturingfluid 910. For the component 916 as the inorganic oxidizer salt, theinorganic oxidizer salt may be added as a solid (powder), for example,via the control device 918 as a rotary feeder valve. Alternatively, theinorganic oxidizer salt may in added in an aqueous dispersion to thefracturing fluid 910 in the source 908 vessel. Moreover, instead ofadding the component 916 to the source 108 vessel, the component 916 maybe added to the discharge conduit of the pump 912 as the pump 912 isproviding the fracturing fluid 910 into the wellbore 902.

The hydraulic fracturing system at the well site 900 may have a sourceof proppant, which can include railcars, hoppers, containers, or binshaving the proppant. Proppant may be segregated by type or mesh size(particle size). The proppant can be, for example, sand or ceramicproppants. The source of proppant may be at the Earth surface 904 nearor adjacent the wellbore 902. The proppant may be added to thefracturing fluid 910 such that the fracturing fluid 910 includes theproppant. In some implementations, the proppant may be added (forexample, via gravity) to a conduit conveying the frac fluid 110, such asat a suction of a fracturing fluid pump 912. A feeder or blender mayreceive proppant from the proppant source and discharge the proppantinto pump 912 suction conduit conveying the fracturing fluid 110.

The fracturing fluid 910 may be a slurry having the solid proppant. Thepump 912 discharge flow rates (frac rates) may include a slurry ratewhich may be a flow rate of the fracturing fluid 910 as slurry havingproppant. The pump 912 discharge flow rates (frac rates) may include aclean rate which is a flow rate of fracturing fluid 910 withoutproppant. In particular implementations, the fracturing systemparameters adjusted may include at least pump(s) 912 rate, proppantconcentration in the frac fluid 910, component 916 addition rate, andcomponent 916 concentration in the fracturing fluid 910. Fracturingoperations can be manual or guided with controllers.

The well site 900 may include a control system 914 that supports or is acomponent of the hydraulic fracturing system. The control system 914includes a processor 920 and memory 922 storing code 924 (logic,instructions) executed by the processor 920 to perform calculations anddirect operations at the well site 900. The processor 920 may be one ormore processors and each processor may have one or more cores. Thehardware processor(s) 920 may include a microprocessor, a centralprocessing unit (CPU), a graphic processing unit (GPU), a controllercard, or other circuitry. The memory may include volatile memory (forexample, cache and random access memory (RAM)), nonvolatile memory (forexample, hard drive, solid-state drive, and read-only memory (ROM)), andfirmware. The control system 914 may include a desktop computer, laptopcomputer, computer server, programmable logic controller (PLC),distributed computing system (DSC), controllers, actuators, controlcards, an instrument or analyzer, and a user interface. In operation,the control system 914 may facilitate processes at the well site 900 andincluding to direct operation of aspects of the hydraulic fracturingsystem.

The control system 914 may be communicatively coupled to a remotecomputing system that performs calculations and provides direction. Thecontrol system 914 may receive user input or remote-computer input thatspecifies the set points of the control device 916 or other controlcomponents in the hydraulic fracturing system. The control system 914may specify the set point of the control device 918 for the component916 addition. In some implementations, the control system 914 maycalculate or otherwise determine the set point of the control device118. The determination may be based at least in part on the operatingconditions of the hydraulic fracturing and on information (or feedback)regarding the amount of kerogen in the region of the geologicalformation 906 being hydraulically fractured.

The fracturing fluid as a VES-based fluid containing oxidative materialsmay be applied (pumped) without other hydraulic fracturing fluidsemployed in the hydraulic fracturing. In other words, the VES-basedfluid containing oxidative materials (for example inorganic oxidizersalt) may be pumped as a stand-alone hydraulic fracturing treatment tofracture the formation and to transport proppant. However, the VES-basedfluid may also be applied (pumped) in tandem (in a sequence) with otherfluids including other hydraulic fracturing fluids.

The VES-based fluid containing oxidative materials and proppant may bepumped alternatively with VES-based fluid containing oxidative materialsand no proppant as a hybrid treatment. The VES-based fracturing fluidmay also be pumped as part of conductivity channel fracturing. In otherapplications, the VES-based fluid containing oxidative materials may bepumped as part of a slickwater hydraulic fracturing operation in whichthe VES fluid is the proppant-laden fluid in the sequence. In certainimplementations, the slickwater includes oxidizer for breaking downkerogen. The slickwater may be pumped before and after the VES fluid inthe hydraulic fracturing. In certain cases, VES fluid is pumped firstfollowed by slickwater fluid or other viscosified fluid so that when theVES fluid enters microfractures, the VES fluid generally does not damagethe formation as slick water polymers can leave residue. The otherviscosified fluid may include, for example, a fracturing fluidviscosified via a polymer.

The VES-based fluid containing oxidative materials may be pumpedalternatively with CO₂-based fluids. A benefit of employing a CO₂-basedfracturing fluid in tandem with the reactive VES-based fracturing fluidis that CO₂ slugs can promote expulsion of hydrocarbons from theformation. Further, CO₂-based fracturing fluid may include an oxidizerto break down organic material (kerogen) in the formation. CO₂ slugs mayenhance delivery of oxidizer to the kerogen. The oxidizer in theCO₂-based fluid may be an organic oxidizer that is soluble in organicsolutions or non-polar media (solvents) because the CO₂-based fracturingfluid may generally be non-polar. These “organic oxidizers” may includean organic cation and an oxidizer inorganic anion. The oxidizerinorganic anion may be, for example, chlorate or bromate. Other oxidizerinorganic anions of the organic oxidizers may include persulfate,perborate, percarbonate, hypochlorite, chlorite, peroxide, or iodate.

Another implementation of a CO₂-based fracturing fluid that may besequenced with the reactive VES-based fracturing fluid is a foamemulsion (oxidizer foam) including CO₂ (or other inert gas), water, andoxidizer to break down the kerogen in the formation during hydraulicfracturing. A benefit may include reduction of water use. Anotherbenefit may be the effect of the inert gas (CO₂) on hydrocarbon recoveryin displacement of hydrocarbons from the kerogen-laden formation. Theoxidizer(s) in the foam may be at least one of an inorganic oxidizer andan organic oxidizer, which may reside in different phases of the foam,respectively.

Yet another implementation of a CO₂-based fracturing fluid that may besequenced with the reactive VES-based fracturing fluid is supercriticalCO₂ fracturing fluid. The supercritical CO₂ may have reactive oxidizergases (for example, bromine, chlorine, chlorine dioxide, or ozone) forthe treatment of kerogen-containing rocks to enhance hydraulicfracturing efficiency of unconventional source rock formations. Thereactive oxidizer gases may chemically degrade kerogen to enhance rockfracability and clean fracture faces to increase permeability anddecrease proppant embedment. The reactive gases may be suited forCO₂-based fracturing fluids because unlike conventional oxidizers, thereactive oxidizer gases here are either soluble in non-polar solvents orcan be mixed and delivered in the non-polar solvent stream. Theoxidizing gas as molecules may exist as a gas or supercritical fluid (atreservoir conditions) that is soluble in supercritical CO₂ and has astandard redox potential in excess of 1 volt. Reservoir conditions maybe, for example, temperature greater than 200° F. and pressure greaterthan 3000 pounds per square inch gauge (psig). These reactive gasesinclude, for example, bromine (Br₂), chlorine (Cl₂), fluorine (F₂),chlorine monofluoride (ClF), chlorine dioxide (ClO₂), oxygen (O₂), ozone(O₃), nitrous oxide (N₂O), or nitrite (NO₂) gases. Reactive gases mayalso be generated in situ upon injection of precursors with CO₂ into theformation.

The technique may involve mixing of supercritical CO₂ with an oxidizinggas stream. These oxidizing gas chemicals can be mixed on-the-fly withliquid CO₂ and surfactant to form the emulsion and pumped. The oxidant(oxidizer) should be consumed downhole and therefore may beneficiallypreclude flowback treatment or disposal. If the oxidant is prepared insitu, then the precursors may be injected with supercritical CO₂. Forexample: (1) the first precursor with CO₂ is injected, (2) a CO₂ spaceris then pumped, and (3) the second precursor with CO₂ is then injected.This sequence may prevent or reduce premature reaction of the precursorsto form the reactive gas.

For bromine as the reactive gas, the bromine reacts with the kerogen andpyrite. The bromine may partially depolymerize the kerogen (ageopolymer). This reaction of bromine with kerogen may form light-chainproducts that escape when the CO₂ is vented. This reaction of brominewith kerogen may also form a brominated kerogen tar at least partiallysoluble in CO₂. This kerogen tar may be soluble in hydrocarbons andtherefore leave the rock matrix migrating from the formation to thewellbore.

As for supply of ClO₂ as an oxidizer in the supercritical CO₂, ClO₂generators commercially available may be deployed at the well site. TheClO₂ gas can be mixed with liquid CO₂ on-the-fly for the stimulation andtreatment of organic-rich shale formation for enhanced hydrocarbonproduction. The ClO₂ gas generally does not hydrolyze when enteringwater and remains a dissolved gas in solution. The ClO₂ gas may be up to10 times more soluble in water than is chlorine and therefore a largerdose (compared to chlorine) of the oxidizer gas ClO₂ can be delivered tothe formation. In lieu of relying on ClO₂ generators, the ClO₂ gas mayinstead be generated in situ (downhole in the wellbore) via, forexample, utilizing sodium chlorite. Over time, produced ClO₂ gas mayhelp degrade the kerogen and increase production. If ClO₂ is theoxidant, ClO₂ should be prepared on site and used as a mixture with air.

Lastly, other CO2-based hydraulic fracturing fluids may be employed intandem with the present reactive VES-based fracturing fluid. Forexample, CO2-based fluids with an oxidizer contain in-situ forminghalogens may be employed.

FIG. 10 is a method 1000 of hydraulic fracturing a geological formation.The geological formation includes organic material, such as kerogen.

At block 1002, the method includes providing a VES fracturing fluidhaving a surfactant and an inorganic oxidizer salt through a wellboreinto the geological formation. In implementations, the method includespumping the VES fracturing fluid through the wellbore into thegeological formation. The pumping may inject the VES fracturing fluidthrough perforations in cemented casing of the wellbore into thegeological formation. The VES fracturing fluid may be a reactive VESfracturing fluid because of the presence of the inorganic oxidizing saltin the VES fracturing fluid. The concentration of the inorganicoxidizing salt in the VES fracturing fluid may be, for example, in arange of 1 wt % to 20 wt %. In some implementations, the concentrationof the inorganic salt in the reactive VES fracturing fluid is at least 3wt % or at least 5 wt %.

The VES fracturing fluid may include water. The VES fracturing fluid mayinclude the surfactant at a concentration in a range of 0.1 wt % to 10wt %. The method may include forming worm-like micelles from moleculesof the surfactant to increase viscosity of the reactive VES fracturingfluid. The reactive VES fracturing fluid may include polymer to furtherincrease viscosity of the reactive VES fracturing fluid. In otherembodiments, the VES fracturing fluid does not include polymer.

The VES fracturing fluid may include another salt that is a monovalentsalt or a divalent salt to promote formation of worm-like micelles frommolecules of the surfactant that entangle to increase viscosity of theVES fracturing fluid. The reactive VES fracturing fluid may have thissalt (for example, a monovalent salt or a divalent salt) that is not anoxidizer to promote micelle formation of the surfactant and with thissalt at a concentration of less than 15 wt % in the VES fracturingfluid.

The method may include optionally adding proppant to the VES fracturingfluid. The VES fracturing fluid have proppant for at least a portion oftime of providing (pumping) the VES fracturing fluid through thewellbore into the geological formation.

At block 1004 the method includes hydraulically fracturing thegeological formation via the providing (pumping) of the VES fracturingfluid to form hydraulic fractures in the geological formation. Theorganic material (for example, kerogen) is present in the hydraulicfractures. Kerogen exists at fracture faces of the hydraulic fractures.In the initial forming of the hydraulic fractures, the kerogen blockspermeability between portions of the fracture faces and the geologicalformation. A fracture face is generally an interface of a hydraulicfracture with the geological formation.

At block 1006, the method includes oxidizing organic material (forexample, kerogen) in the hydraulic fractures with the VES fracturingfluid. The oxidizing of the organic material may involve degrading andfragmenting the organic material. The oxidizing of the organic materialmay make the organic material (or at least a portion of the organicmaterial) soluble in aqueous fluid. The degrading of the organicmaterial may involve fragmenting the organic material to generate apermeable channel through the organic material. The oxidizing mayinclude oxidizing organic material at a fracture face of the hydraulicfracture to fragment the organic material at the fracture face togenerate a permeable channel from the geological formation into thehydraulic fracture. The generating the permeable channel increasesconductivity of hydrocarbon from the geological formation through thehydraulic fracture to the wellbore. While fragments of the organicmaterial may remain at the fracture face, the permeability is increaseddue the oxidation and attack by the VES fracturing fluid having theinorganic oxidizer salt. The oxidizing may include degrading the organicmaterial involving dividing the organic material into pieces that can besolubilized in aqueous treatment fluid that is flowed back through thewellbore to the Earth surface.

At block 1008, the method includes specifying a concentration of theinorganic oxidizer salt in a VES fracturing fluid. The method mayinclude specifying a concentration of the inorganic oxidizer salt in theVES fracturing fluid (reactive) based at least in part on an amount ofkerogen in the geological formation. The VES fracturing fluid mayinclude the inorganic oxidizer salt at the concentration as specified.The method may include adding the inorganic oxidizer salt to thereactive VES fracturing fluid to give the concentration as specified.

The concentration of the inorganic oxidizer salt in the VES fracturingfluid can depend on the quantity of kerogen or other organic matter inthe reservoir rock in the geological formation, such as in the region ofthe geological formation being subjected to hydraulic fracturing withthe VES fracturing fluid. The concentration of the inorganic oxidizersalt in the VES fracturing fluid to implement can be determined(specified) based on the particular inorganic oxidizer salt selected andon the amount and type of kerogen in the geological formation.Source-rock samples collected from the geological formation beinghydraulically fractured or to be hydraulically fractured can becollected and analyzed. For example, laboratory tests (for instance,including etching) can be performed on kerogen embedded in rock surfacesof the samples. Further, the weight percent of the total organic carbon(TOC) in the formation can be determined, for example, via a TOCanalyzer or pyrolysis unit. The amount of kerogen in the subterraneanregion of the geological formation to be hydraulically fractured can becalculated, determined, or estimated.

The amount of pyrite or other iron sulfides in the subterraneanformation may also be considered in specifying the concentration of theinorganic oxidizer salt in the VES fracturing fluid. The weight percentof iron sulfide in the formation can be determined, for example, bytesting the source-rock samples employing x-ray fluorescence, x-raydiffraction, or energy dispersive x-ray spectroscopy. The amount ofkerogen or iron sulfide can also be taken, deduced, or inferred fromwell logs in certain instances. The determining or specifying theinorganic oxidizer salt concentration can account for the amount ofinorganic oxidizer salt needed to degrade the organic material includingkerogen while also accounting for the iron sulfide present in theformation.

The rock surface area within the fracture network that the reactive VESfluid will make contact in the formation can be considered with respectto specifying concentration of the inorganic oxidizer salt in the VESfluid. The expected size of the fracture network and the resultingsurface area of the fractured zones can be estimated. Other factorsrelevant in determining or calculating the amount (concentration) ofinorganic oxidizer salt to specify in the reactive VES fluid mayinclude: (1) any organic components in the VES fluid; and (2) anyorganic components and amount of fluid downhole (including in thewellbore) at the time of placing the reactive VES fluid through thewellbore into the geological formation.

At block 1010, the method optionally includes alternating or sequencingthe reactive VES fracturing fluid. The VES-based fluid containingoxidative materials and proppant may be pumped alternatively withVES-based fluid containing oxidative materials and no proppant as ahybrid treatment. The VES-based fracturing fluid may also be pumped aspart of conductivity channel fracturing. In other applications, themethod may include providing (pumping) a slickwater fracturing fluidthrough the wellbore into the geological formation before (and after)providing the VES fracturing fluid through the wellbore into thegeological formation. The slickwater fracturing fluid may include anoxidizer. The VES fracturing fluid may include proppant. The method mayinclude pumping a slickwater fracturing fluid through the wellbore intothe geological formation in sequence with the pumping of the reactiveVES-based fracturing fluid, where the VES-based fracturing fluid hasproppant.

The method may include a sequence that alternates pumping a CO₂-basedfracturing fluid with pumping the VES fracturing fluid having theoxidizer. The method may include alternating in a sequence: (1)providing a CO₂-based fracturing fluid through the wellbore into thegeological formation with (2) providing the VES fracturing fluid throughthe wellbore into the geological formation. The CO₂-based fracturingfluid may have an oxidizer to attack kerogen.

At block 1012, the method may further include in addition to hydraulicfracturing, the production of hydrocarbon from the geological formation.The method may include producing hydrocarbon from the geologicalformation through the permeable channel (block 1006) and the hydraulicfracture(s) to the wellbore.

At block 1014, the method may include applying a reactive VES fluid fortreatments other than hydraulic fracturing. This reactive VES-basedtreatment fluid may be the same or similar as the aforementioned VESfracturing fluid applied for hydraulic fracturing. These additionaltreatments may be outside of the context of hydraulic fracturing or incombination with the hydraulic fracturing. Implementations of treatmentswith the VES-based treatment fluid include: (1) upgrading oil in thesubterranean formation (geological formation) by oxidizing the oil toreduce the boiling point of the oil; (2) degrading filter cake duringopenhole drilling or during hydraulic fracturing; (3) breaking organicmatter (for example, paraffin, bitumen, or oil) in the subterraneanformation by reducing the viscosity of the organic matter; and (4)removing organic scale (buildup) from a subterranean formation forclean-up to facilitate subsequent fluid injection for the wellboreemployed as an injection well. The inorganic oxidizer salt in the VEStreatment fluid may include iodates (IO₃ ⁻).

Iodate salts may be included as the inorganic oxidizer salt in the VESfluid for options of heavy oil upgrading, in situ methane conversion,and other applications. The iodate salt may be IO₃ ⁻ paired withlithium, sodium, potassium, magnesium, etc.

An implementation may be to pump the present VES fluid (having aninorganic oxidizer salt) through a wellbore into the subterraneanformation to upgrade heavy oil in the subterranean formation. Theupgrade of the heavy oil may be performed with the wellbore as anopenhole wellbore. Heavy oil can include asphalt and bitumen. Heavy oilmay be crude oil having an API gravity less than 22°, less than 21°, orless than 20°. Heavy oil may be crude oil having an API gravity in therange of 10° to 22°, 10° to 21°, or 10° to 20°. Crude oil with an APIgravity less than 10° can be characterized or labeled as extra-heavycrude oil. The VES fluid (VES-based fluid) can be employed to upgradeheavy oil or extra-heavy oil. The upgrade may be to reduce the boilingpoint and viscosity of the heavy oil. The oxidization of the heavy oilby the VES fluid may degrade the heavy oil. The degradation may upgradethe heavy oil in the sense of reducing the boiling point and viscosity.The oxidation may dissolve resinous components of the heavy oil. Theoxidation may reduce the molecular weight of the heavy oil by breakingmolecular chains (molecules) of the heavy oil into shorter chains(molecules) and thus reduce the viscosity and boiling point of the heavyoil.

Another implementation is to pump the present reactive VES fluid(reactive VES-based fluid) through a wellbore into the subterraneanformation to degrade and remove filter cake. A property of drillingfluid (mud) may be the formation of a filter cake. This filter cake maybe deposited on the porous rocks under overbalance pressure conditions.Filter cake (mud cake or wall cake) may be a layer formed by solidparticles in drilling mud against porous zones due to differentialpressure between hydrostatic pressure and formation pressure. Thestructure of the filter cake may include a solid deposition insoluble inwater. The material insoluble in water may be organic material. Theremoval of the filter cake with the present VES fluid may be in openholedrilling or during hydraulic fracturing. The VES fluid may oxidize(attack) the filter cake to break down and dissolve (or dislodge) thefilter cake. The oxidizing of organic material with the reactive VESfluid may involve degrading a filter cake with the reactive VES fluidduring drilling of the wellbore as an openhole wellbore or duringhydraulic fracturing of the subterranean (geological) formation.

Other implementations include to pump the reactive VES fluid (reactiveVES-based fluid) through a wellbore into a subterranean formation tobreak organic matter (for example, paraffin, bitumen, or oil) in thesubterranean formation. The breaking (reducing the viscosity) of theorganic matter may be by oxidation via the VES fluid. The oxidation maydissolve or partially dissolve the organic matter to reduce viscosity.Such may advance formation conductivity and thus subsequent oil and gasproduction. Yet other implementations may pump the present VES through awellbore of an injection well to remove organic scale (buildup, residue)from a subterranean formation for clean-up of the organic scale. Suchmay facilitate subsequent fluid injection through the wellbore andsubterranean formation in the operation of the injection well.

EXAMPLES

The Examples are given only as examples and not meant to limit thepresent techniques. Example 1 and Example 2 are initially presented.

Example 1

Example 1 is directed to evaluating substitution of sodium bromate (aninorganic oxidizer salt) for typical salt in a VES fluid. In particular,three VES-based fluids were prepared in order to determine the effect ofadding strong oxidizing salts (sodium bromate in particular inExample 1) to the fluid mixture and whether an oxidizing salt couldreplace the calcium chloride (or potassium chloride) typically used inVES fluids for hydraulic fracturing applications. The three VES fluidswere prepared with water and erucamidopropyl hydroxypropylsultaine (asthe viscoelastic surfactant) commercially known as Armovis EHS®available from Akzo Nobel N.V. having headquarters in Amsterdam,Netherlands. Salt was added to the three VES fluids. In particular thethree VES fluids included: (1) the VES fluid containing calcium chloride(CaCl₂) salt; (2) the VES fluid containing both CaCl₂ salt and sodiumbromate (NaBrO₃) oxidizer salt; and (3) the VES fluid containing NaBrO₃oxidizer salt.

FIG. 11 is Table 1 (1100) giving solution parameters for these three VESfluid samples prepared for viscosity measurements. The sample column1102 notes the respective sample number of 1, 2, or 3. The water 1104 ineach sample was 135 milliliters (mL). The VES 1106 (erucamidopropylhydroxypropylsultaine) in each sample was 7.5 mL. The amount 1108 ofcalcium chloride dehydrate (CaCl₂.2H₂O) is given in grams (g). Themolality (m) 1110 of CaCl₂ is given in kilogram per mole of solution ofthe respective VES fluid samples. The amount 1112 of NaBrO₃ is given ingrams (g). The molality (m) 1114 of NaBrO₃ is given in kilogram per moleof solution of the respective VES fluid samples. The total ion molality1116 is give in kilograms per mole of solution of the respective VESfluid samples. The three samples of the VES fluids were prepared byfirst dissolving the salt(s) in the volume of water 1104 listed in thetable. Then, the VES 1108 was added and the solution agitated formixing.

After each fluid was prepared, the viscosity was measured with arheometer. The temperature was initially ramped to 200° F. and helduntil the viscosity stabilized. The viscosity of all three fluids weresimilar (around 200 cP) with the highest viscosity (about 230 cP)corresponding to the highest total ion molality in solution and thelowest viscosity (about 175 cP) corresponding to the lowest total ionmolality in solution. The effect of oxidizing salt as a replacement oraddition is beneficially negligible, which suggests that the chargeadded by this salt is sufficient to encourage worm-like micelleformation in solution. This evaluation also shows that the surfactant isnot susceptible to oxidative degradation at these temperatures. Thesetwo factors demonstrate that this fluid could be effectively pumped intothe unconventional source rock formation.

In the tests, the temperature of the fluids were ramped and held to aseries of greater temperatures: 250° F., 300° F., and 350° F. At 250°F., the viscosities of the fluids notably drop to about 100 cP, but theviscosities are stable at that temperature suggesting that the fluidshad not degraded. Further temperature ramping (through 300° F. to 350°F.) shows the viscosity dropping to about 0 cP. These temperatures of300+° F., however, are beyond the temperatures at which these fluids arepumped and therefore do not limit application of the fluids.

FIG. 12 is a plot 1200 of viscosity (cP) 1202 and temperature (° F.)1204 over time 1206 in hours (h). The plot 1200 gives rheological datafor the three samples of VES-based fluid. The curve 1208 is theviscosity of sample 1. The curve 1210 is the viscosity of sample 2. Thecurve 1212 is the viscosity of sample 3. The three curves 1214 fortemperature of the three samples, respectively, are essentially same atthe relevant portion (temperatures) of the tests.

Example 2

Example 2 is directed to evaluating stability of a VES-based fluidhaving an inorganic oxidizer salt and a polymer. A polymer may be addedto a VES fluid to boost viscosity of the VES fluid. However, the polymermay be susceptible to oxidative degradation. To evaluate whether suchdegradation would occur at the temperatures and timescale of a hydraulicfracturing job with a reactive VES, a VES fluid containing sodiumbromate (an inorganic oxidizer salt) as the sole salt was prepared withthree different amounts of a polymer. The polymer was Flopaam™ 5915 SH(abbreviated here as FP5915SH) from SNF Floerger having headquarters inAndrézieux, France. The FP5915SH polymer is a hydrophobically modifiedanionic-polyacrylamide-based terpolymer with the hydrophobic monomercontent less than 1.5 mol % and containing 10-25 mol % of sulfonicmonomer. The FP5915SH polymer was added in slurry form to three VESfluid samples.

FIG. 13 is Table 2 (1300) giving components of the tested fluids (thethree VES fluid samples). Table 2 are solution parameters for the threeVES fluids prepared with polymer additive FP9515SH for viscositymeasurement. The sample column 1302 notes the respective sample numberof 4, 5, or 6. The water 1304 in each sample was 135 mL. The VES 1306(erucamidopropyl hydroxypropylsultaine) in each sample was 7.5 mL. Thevolume 1308 of FP9515SH polymer slurry added is given in mL. The amount1310 of NaBrO₃ is given in grams (g). The molality (m) 1312 of NaBrO₃ isgiven in kilogram per mole of solution of the respective VES fluidsamples.

FIG. 14 is a plot 1400 of viscosity (cP) 1402 and temperature (° F.)1404 over time 1406 in hours (h). The plot 1400 gives rheological datafor the three samples of VES-based fluid prepared with the FP9515SHpolymer. Fluid compositional data is given in Table 2 of FIG. 13. InFIG. 14, the curve 1408 is the viscosity of sample 4. The curve 1410 isthe viscosity of sample 5. The curve 1412 is the viscosity of sample 6.The curves 1414 is the approximate temperature of the three samples 4,5, and 6 during the viscosity during the viscosity measurements. As canbe seen in plot 1400, increasing addition of the polyacrylamideterpolymer (FP9515SH) increases the viscosity of the VES fluid. Thefluid is stable at 200° F.

An embodiment is a method of hydraulic fracturing, including providing aVES fracturing fluid having a surfactant and an inorganic oxidizer saltthrough a wellbore into a geological formation to hydraulically fracturethe geological formation to form a hydraulic fracture in the geologicalformation. The method includes oxidizing organic material in thehydraulic fracture with the VES fracturing fluid. The oxidizing of theorganic material includes degrading (for example, fragmenting) theorganic material, which includes kerogen. The oxidizing of the organicmaterial may make at least a portion of the organic material soluble inaqueous fluid. The degrading of the organic material may involvefragmenting the organic material to generate a permeable channel throughthe organic material. The oxidizing may include oxidizing organicmaterial at a fracture face of the hydraulic fracture to fragment theorganic material at the fracture face to generate a permeable channelfrom the geological formation into the hydraulic fracture to increaseconductivity of hydrocarbon from the geological formation through thehydraulic fracture to the wellbore. The fracture face may be aninterface of the hydraulic fracture with the geological formation.

In certain implementations, the VES fracturing fluid does not includepolymer. The concentration of the surfactant in the VES fracturing fluidmay be in a range of 0.1 wt % to 10 wt %. The method may includespecifying a concentration of the inorganic oxidizer salt in the VESfracturing fluid based at least in part on an amount of kerogen in thegeological formation. The VES fracturing fluid may have the inorganicoxidizer salt at the concentration as specified. The concentration ofthe inorganic salt in the VES fracturing fluid may be in a range of 1 wt% to 20 wt %. The inorganic oxidizer salt may include LiClO₃, NaClO₃,KClO₃, Mg(ClO₃)₂, Ca(ClO₃)₂, Sr(ClO₃)₂, Ba(ClO₃)₂, LiBrO₃, NaBrO₃,KBrO₃, Mg(BrO₃)₂, Ca(BrO₃)₂, Sr(BrO₃)₂, or Ba(BrO₃)₂, or anycombinations thereof. The inorganic oxidizer salt may include iodates(IO₃ ⁻).

Iodate salts may be including as the inorganic oxidizer salt with thepresent VES as a delivery method, for example, for options of heavy oilupgrading, in situ methane conversion, and other applications. Thespecific iodate (IO₃ ⁻) salt may be similar salts to the aforementionedsalts with lithium, sodium, potassium, magnesium, etc.

The VES fracturing fluid may have another salt (in addition to theinorganic oxidizer salt) that is a monovalent salt or a divalent salt topromote formation of worm-like micelles from molecules of the surfactantthat entangle to increase viscosity of the VES fracturing fluid. Theother salt may include LiF, NaF, KF, MgF₂, CaF₂, SrF₂, BaF₂, LiCl, NaCl,KCl, MgCl₂, CaCl₂, SrCl₂, BaCl₂, LiBr, NaBr, KBr, MgBr₂, CaBr₂, SrBr₂,or BaBr₂, or any combinations thereof. The salt may alter the inductiontime for oxidizer to react with ammonium cations and form acid.

The method may include adding proppant to the VES fracturing fluid. TheVES fracturing fluid may include the proppant for at least a portion oftime of providing the VES fracturing fluid through the wellbore into thegeological formation. The method may include providing a slickwaterfracturing fluid (for example, also having an oxidizer) through thewellbore into the geological formation before or after providing the VESfracturing fluid through the wellbore into the geological formation. Themethod may include providing a viscosified fracturing fluid through thewellbore into the geological formation before or after providing the VESfracturing fluid through the wellbore into the geological formation. Themethod may include providing a CO₂-based fracturing fluid through thewellbore into the geological formation before or after providing the VESfracturing fluid through the wellbore into the geological formation. TheCO₂-based fracturing fluid may have an organic oxidizer that attacks theorganic material. The CO₂-based fracturing fluid includes a reactive gasthat attacks the organic material. The reactive gas may be, for example,Br₂, Cl₂, F₂, ClF, ClO₂, O₂, O₃, N₂O, or NO₂, or any combinationsthereof.

Another embodiment is a method including pumping a reactive VESfracturing fluid having a surfactant and an inorganic oxidizer saltthrough a wellbore into a geological formation for hydraulic fracturingof the geological formation. The method includes forming hydraulicfractures in the geological formation with the reactive VES fracturingfluid and oxidizing organic material in the hydraulic fractures with thereactive VES fracturing fluid. The method includes generating apermeable channel through organic material at a fracture face of ahydraulic fracture between the geological formation and the hydraulicfracture via oxidizing of the organic material at the fracture face withthe reactive VES fracturing fluid. The oxidizing of the organic material(for example, including kerogen) at the fracture face may fragment theorganic material at the fracture face. In certain implementations, theconcentration of the inorganic salt in the reactive VES fracturing fluidis at least 3 wt %. In some implementations, the inorganic oxidizer saltmay include magnesium peroxide, calcium peroxide, sodium nitrate, sodiumnitrite, sodium persulfate, potassium persulfate, sodium tetraborate,sodium percarbonate, sodium hypochlorite, calcium hypochlorite, aniodate salt, a chlorite salt, a periodate salt, a dichromate salt, or apermanganate salt, or any combinations thereof. The oxidizing mayinclude degrading the organic material involving dividing the organicmaterial into pieces that can be solubilized in aqueous treatment fluidthat is flowed back through the wellbore to the Earth surface.

The method may include forming worm-like micelles from molecules of thesurfactant to increase viscosity of the reactive VES fracturing fluid.The reactive VES fracturing fluid may further include polymer to furtherincrease viscosity of the reactive VES fracturing fluid. The reactiveVES fracturing fluid may include a salt that is not an oxidizer topromote micelle formation of the surfactant. This salt may be, forexample, a monovalent salt or a divalent salt and at a concentration inthe reactive VES fracturing fluid less than 15 wt %. The method mayinclude specifying a concentration of the inorganic oxidizer salt in thereactive VES fracturing fluid based at least in part on an amount ofkerogen in the geological formation. The method may include adding theinorganic oxidizer salt to the reactive VES fracturing fluid to give theconcentration as specified. The reactive VES fracturing fluid mayinclude proppant for at least a portion of time of pumping the reactiveVES fracturing fluid through the wellbore into the geological formation.The method may include pumping a slickwater fracturing fluid through thewellbore into the geological formation in sequence with the pumping ofthe reactive VES-based fracturing fluid having proppant in the sequence.The method may include producing hydrocarbon from the geologicalformation through the permeable channel and the hydraulic fracture tothe wellbore.

Yet another embodiment is a reactive VES fracturing fluid for hydraulicfracturing of a geological formation. The reactive VES fracturing fluidincludes a surfactant at a concentration in the reactive VES fracturingfluid in a range of 0.1 wt % to 10 wt %. The reactive VES fracturingfluid includes an inorganic oxidizer salt for the reactive VESfracturing fluid to degrade kerogen in the geological formation. Theconcentration of the inorganic oxidizer salt in the VES fracturing fluidmay be in a range of 1 wt % to 20 wt %. The concentration of theinorganic oxidizer salt in the VES fracturing fluid may be at least 3 wt%. In implementations, the inorganic oxidizer salt may promote micelleformation of the surfactant. The inorganic oxidizer salt may includeLiClO₃, NaClO₃, KClO₃, Mg(ClO₃)₂, Ca(ClO₃)₂, Sr(ClO₃)₂, Ba(ClO₃)₂,LiBrO₃, NaBrO₃, KBrO₃, Mg(BrO₃)₂, Ca(BrO₃)₂, Sr(BrO₃)₂, or Ba(BrO₃)₂, orany combinations thereof. The inorganic oxidizer salt may includemagnesium peroxide, calcium peroxide, sodium nitrate, sodium nitrite,sodium persulfate, potassium persulfate, sodium tetraborate, sodiumpercarbonate, sodium hypochlorite, an iodate salt, a periodate salt, adichromate salt, or a permanganate salt, or any combinations thereof.The reactive VES fracturing fluid may include a salt that is not theinorganic oxidizer salt, that is inert to oxidation, and that promotesmicelle formation of the surfactant to increase viscosity of thereactive VES fracturing fluid. The salt may also accelerate or delay theformation of acid. Concentration of this salt (for example, a monovalentsalt or a divalent salt) in the reactive VES fracturing fluid isgenerally in a range of 0.1 wt % to 30 wt %, or may be less than 15 wt%. This salt that is not the inorganic oxidizer salt may include LiF,NaF, KF, MgF₂, CaF₂, SrF₂, BaF₂, LiCl, NaCl, KCl, MgCl₂, CaCl₂, SrCl₂,BaCl₂, LiBr, NaBr, KBr, MgBr₂, CaBr₂, SrBr₂, or BaBr₂, or anycombinations thereof. The reactive VES fracturing fluid may includephthalic acid, salicylic acid, or their salts, or any combinationthereof. The reactive VES fracturing fluid may include a crosslinkablepolymer. The reactive VES fracturing fluid may include a crosslinkedpolymer that increases viscosity of the reactive VES fracturing fluid.

Yet another embodiment is a reactive VES fracturing fluid for hydraulicfracturing of a subterranean formation. The reactive VES fracturingfluid includes water (for example seawater), a surfactant at aconcentration in the reactive VES fracturing fluid in a range of 0.5 wt% to 10 wt %, and an inorganic oxidizer salt for the reactive VESfracturing fluid to oxidize kerogen in the subterranean formation tofragment the kerogen. The VES fracturing fluid may have another saltincluding a monovalent salt or a divalent salt, or a combinationthereof, to promote micelle formation of the surfactant. The surfactantmay be a zwitterionic surfactant that is a betaine or a sultaine. Thesurfactant may be a zwitterionic surfactant that is a dihydroxyl alkylglycinate, alkyl ampho acetate or propionate, alkyl amidoamine oxide,gemini VES, alkyl betaine, alkyl amidopropyl betaine, alkyliminomono-propionates, or alkylimino di-propionates, or any combinationsthereof. The surfactant may be a zwitterionic surfactant that isdisodium tallowiminodipropionate, disodium oleamidopropyl betaine, orerucylamidopropyl betaine, or any combinations thereof. The surfactantmay be a cationic surfactant, such as an alkylammonium salt. Thealkylammonium salt may include oleyl methyl bis(2-hydroxyethyl)ammoniumchloride, erucyl bis(2-hydroxylethyl)methylammonium chloride, N, N, N,trimethyl-1-octadecammonium chloride, cetyltrimethylammonium bromide(CTAB), or dimethylene-1,2-bis(dodecyldimethylammonium bromide), or anycombinations thereof. The surfactant may include an anionic surfactant,such as at least one of an alkyl sarcosinate or a sulfanate. Thesurfactant may include a nonionic surfactant, such as an amido aminooxide. In implementations, the surfactant may include a first surfactantthat is a cationic surfactant and a second surfactant that is an anionicsurfactant.

Yet another embodiment is a method of applying a reactive VES-basedfluid. The method includes providing the reactive VES-based fluid havinga surfactant and an inorganic oxidizer salt through a wellbore into asubterranean formation. The concentration of the inorganic oxidizer saltin the reactive VES-based fluid is in a range of 1 wt % to 20 wt %. Incertain implementations, the concentration is at least is at least 3 wt%. The method includes oxidizing organic material in the subterraneanformation with the reactive VES-based fluid. In some implementations, afilter cake includes the organic material. If so, the oxidizing of theorganic material involves degrading the filter cake with the reactiveVES-based fluid and where the wellbore is an openhole wellbore. Theoxidizing of organic material may include degrading a filter cake withthe reactive VES-based fluid during drilling of the wellbore, where thewellbore includes an openhole wellbore. The oxidizing of organicmaterial may include degrading a filter cake with the reactive VES-basedfluid during hydraulic fracturing of the subterranean formation with thereactive VES-based fluid.

In implementations, an injection well includes the wellbore. In theseimplementations, the oxidizing of the organic material involvesoxidizing accumulated organic material to remove the accumulated organicmaterial (for example, organic scale or organic residue) to promotefluid injection through the injection well into the subterraneanformation. In other implementations, the oxidizing of the organicmaterial involves upgrading oil in subterranean formation with thereactive VES-based fluid. The wellbore may be an openhole wellbore. Theoil includes heavy oil having an American Petroleum Institute (API)gravity less than 20°. In implementations, the oxidizing of the organicmaterial comprises includes breaking organic matter in subterraneanformation with the reactive VES-based fluid. The organic matter includesheavy oil or paraffin, or a combination thereof.

Certain embodiments of the present techniques are directed to filtercake removal. The filter cake may be a very thin and impermeable layerwith permeability ranging from 0.01 to 0.0001 millidarcy (md), whichforms of solid materials deposited from the drilling fluid over the faceof the permeable formation at the wellbore, as illustrated in FIG. 15.Filter cake formation may be beneficial or necessary during the drillingprocess because the filter cake may provide several functions fordrilling, such as stabilizing the drilled formations, reducing drillingfluid filtration into the drilled formations, and reducing the solidparticles invasion into the oil-bearing formations (and thus reduceassociated formation damage. However, after the drilling operations, thedrilling fluids and the filter cake film should generally be removedfrom the wellbore to enable a successful primary cementing job. Failureto remove the filter cake layer may lead to formation of a weak bondbetween the cement sheath and the formation rock. Also, filter cakeremoval may be advantageous or mandatory before the start of productionoperations to prevent or reduce impeding of the flow capacity at thewellbore. Filter cake removal could also enhance the injectivity of thefluids through injection wells. FIG. 15 is a schematic of the drillingprocess demonstrating the formation of filter cake on the walls of thewellbore while drilling mud is circulated. Solids from the drilling mudslurry builds on the surface of the formation as filter cake.

FIG. 15 is a well 1500 having a filter cake 1502. The well 1500 includesa wellbore 1504 formed in a subterranean formation 1506. The face of theformation 1506 is formed by drilling is the wellbore 1504 wall. A drillstring 1508 and drill bit 1510 are disposed in the wellbore 1504. In thedrilling operation, drilling fluid 1512 is injected (pumped) into thedrill string 1508. The drilling fluid 1512 may be pumped, for example,be mud pumps from the Earth surface into the drill string 1508 in thewellbore 1502.

The well site of the well 1500 may include surface equipment, such as amounted drilling rig, piping, storage tanks, and so on, at the Earthsurface. The surface equipment may include the aforementioned mud pumpsthat may be, for example, centrifugal pumps, positive displacementpumps, reciprocating pumps, piston pumps, etc.

The wellbore 1504 diameter may be, for example, in a range from about3.5 inches (8.9 centimeters) to 30 inches (76 centimeters), or outsideof this range. The depth of the 1502 can range from 300 feet (100meters) to more than 30,000 feet (9,100 meters). The wellbore 1504 canbe vertical, horizontal, or deviated, or any combinations thereof. Oncethe wellbore 1502 is drilled, the wellbore 1502 may be completed.

To form a hole in the ground, the drill bit 1510 (having cutters) may belowered into the wellbore 1504 and rotated to break the rock of theformation 1504. In the rotation, the cutters may interface with theformation 1506 to grind, cut, scrape, shear, crush, or fracture rock todrill the hole. The drill bit 1510 may be a component of the drillstring 1508 or coupled to the drill string 1508. The drill bit 1510 maybe lowered via the drill string 1508 into the wellbore 1504 (borehole)to drill the wellbore 1504 into the subterranean formation 1506 in theEarth crust. In operation, the drilling fluid 1510, also known asdrilling mud, is circulated down the drill string 1508 and throughmultiple nozzles in the drill bit 1510 to the bottom of the wellbore1504. The drilling fluid 1512 may then flow upward towards the surfacethrough an annulus between the drill string 1510 and the wall of thewellbore 1504. The drilling fluid 1512 may cool the drill bit 1510,apply hydrostatic pressure upon the formation 1506 penetrated by thewellbore 1504 to prevent or reduce fluids from flowing into the wellbore1502, reduce the torque and the drag force induced by the frictionbetween the drill string 1508 and the wellbore 1504 wall, carry theformation cuttings up to the surface, and so forth.

The filter cake 1502 may be formed via the circulating drilling fluid1512. Solids from the drilling fluid 1512 (a slurry) may build on thesurface (face) of the formation 1506 (wellbore 1504 wall) as the filtercake 1502. The filter cake 1502 may form as solids of the drilling fluid1512 slurry deposit on permeable portions of the formation 1506 faceunder wellbore 1504 pressure. Initially, as the filter cake 1502 isbeing deposited on the surface of the permeable material (permeableformation 1506), the material firstly serves as a filter and allows theliquid portions (filtrate) of the drilling fluid 1512 to pass throughand trapping the insoluble solid portion as a cake. Over time, enoughfilter cake gathers on the surface of the permeable material (porousformation 1506), allowing little or no further liquid invasion. Thedrilling fluid 1512 may be configured for formation of the filter cake1502. This filter cake 1502 may be deposited on the porous rocks underoverbalance pressure conditions. The formation of filter cake 1512 mayprevent or reduce further loss of drilling fluid 1512 into the formation1506 and reduce solid invasion as well. In other words, the filter cake1512 may help prevent loss circulation and formation damage that wouldbe caused by fines and filtrate invasion into reservoir rocks. A filtercake 1502 that is relative thin and with low permeability may generallybe desirable.

FIG. 16 is a sequence 1600 of particle buildup of filter cake (e.g.,1502 in FIG. 15) on the surface of the face of the subterraneanformation in a wellbore. The particles 1602, 1604 signify solidcomponents of the drilling mud formulation. The circles 1606 signify thegranular porous nature of the subterranean rock formation, where some ofthe filter cake can invade into the formation. In the first diagram 1608in the time sequence, the particles 1602, 1604 in the drilling fluid aredepicted flowing toward the formation, as indicated by arrow 1610. Inthe second diagram 1612 in the time sequence later in time, theparticles 1602, 1604 accumulate on the formation face (wellbore wall) informing the filter cake. In this illustrated implementation, some of thesmaller particles 1602 may invade into the formation. The third diagram1614 in the time sequence is later in which the filter cake may beconsidered formed. The filter cake may be characterized as thecollection of particles 1602, 1608 at the formation face. The build ofthe particles 1602, 1604 including the dense accumulation of the smallerparticles 1602 may desirably provide for low permeability of the filtercake.

Filter cake removal may pose challenges. Water-based drilling fluid(drilling muds) may contain, for example, calcium carbonate, bentonite,barite, ilmenite, or manganese tetroxide as a weighting agent Thus, thefilter cake including solids collected from the drilling fluid may havethe weighting agent (a solid) (e.g., which may be about 80 wt % of thefilter cake). Treatment solutions for cleaning up the filter cake maytarget this weighting agent as a predominant material from the drillingfluid in the filter cake.

One challenge may be that the polymer also from the drilling fluid inthe filter cake (e.g., 10-15 wt % of the filter cake) may not degrade inthe same treatment fluid designed for the weighting material. Acid, forexample, can dissolve calcium carbonate but generally not polymer. Also,additives for breaking the polymer are often not compatible with thetreating fluid. Further, the deposition of the filter cake may not beheterogeneous, and the polymer may be the predominant component of thetop layer, meaning the polymer may need to be penetrated in order totreat the remainder of the filter cake.

A second challenge may be treating long horizontal sections of awellbore, where uniform cleanup of the filter cake may be difficult.Acid or other reactive treatment fluids may be spent quickly near theheel of the well so that treatment does not extend to the end of thelateral. FIG. 17 is a well 1700 having a wellbore 1702 formed throughthe Earth surface 1704 into a subterranean formation 1706. The wellbore1702 has a horizontal portion 1708 in a hydrocarbon reservoir section1710 of the formation 1706. The wellbore 1702 has a filter cake 1712,such as that depicted in the third diagram 1614 of FIG. 16. A treatmentfluid 1714 is injected into the wellbore 1702 to remove the filter cake1712. For a treatment fluid 1714 having acid, such as hydrochloric acid,the acid may be spent quickly and thus may only treat (remove) thefilter cake 1712 in a small section 1716 of the wellbore 1702. Thus, thesecond challenge may be stated as how to divert active treating fluid1714 to the end portion 1718 of the long lateral of the wellbore 1702.

In certain implementations of the present techniques, the twoaforementioned challenges may be addressed via a treatment fluid as aVES gelled fluid that contains a reactive breaker (oxidizing salt). Thebreaker even at high concentration (e.g., saturated in the treatmentfluid) generally does not affect the gelling performance of the VES inimplementations, but may break polymer upon exposure. By utilizing agel, some of the oxidizing salt in the treatment fluid may extend acrossthe lateral to break polymer in the filter cake at the end portion ofthe wellbore lateral. The oxidizing salt as the breaker may be at orbelow saturated conditions in the reactive treatment fluid. Theoxidizing salt can exceed saturation. The concentration of the oxidizingsalt can be in excess of that to break the polymer. The concentration ofthe oxidizing salt in the reactive treatment fluid may be specifiedbased on (correlative with) the thickness of the filter cake and theparticular well or section of the wellbore. The oxidizing salt mayinclude bromate or other oxidizing anion. An example of the oxidizingsalt is sodium bromate (NaBrO₃). In one implementation, the oxidizingsalt is NaBrO₃ and is saturated (e.g., at greater than 22 wt %) in thereactive treatment fluid. The saturation concentration of the breaker(oxidizing salt) may be a function of the temperature of the reactivetreatment fluid.

Further, the reactive treatment fluid can contain an acid-generatingmaterial that is neutral during mixing at Earth surface and duringinitial pumping into the wellbore. Once the treatment fluid increases intemperature in the wellbore due to heat provided by the subterraneanformation, acid may be generated by the acid-generating material. Othertriggers may also cause the reaction to occur that results in acidformation such as pH change. The acid may lower the viscosity of thegel. The acid may dissolve weighting material (e.g., calcium carbonate)of the filter cake.

Multiple techniques may be employed to generate acid in situ. A widerange of acids can be produced depending on the technique. An acidgenerated may be hydrochloric acid. The generation of the acid mayinvolve liberation of hydrogen ions or hydrogen chloride.

A first technique may be to include a solid acid-generating materialthat is degradable. As the treatment fluid is applied in (flows through)the wellbore, the solid acid-generating material may degrade over time(due to formation temperature) to generate acid. The acid may lower theviscosity of the treatment fluid and also attack or dissolve theweighting agent (e.g., calcium carbonate) in the filter cake. The solidacid-generating material (degradable) may be solid particles and may be,for example, polylactic acid (PLA) (also known as polylactide),polyglycolic acid (PGA), an orthoester, or a polyanhydride, or anycombinations thereof. The size of the particles can be, for example, inranges of 20 microns (μm) to 2 mm, 100 microns to 1 mm, 100 microns to500 microns, 125 microns to 400 microns, or 150 microns to 200 microns.The particular solid acid-generating material selected or specified maybe based at least in part on the formation temperature (welltemperature). For instance, in some implementations, PLA may beutilized, for example, for wells have higher temperature (e.g., at least200° F. or in a range of 200° F. to 350° F. In another example, PGA maybe utilized for wells with lower temperature, such as less than 200° F.or in a range of 140° F. to 200° F.

A second technique to generate acid in situ may be to incorporate anester(s) into the reactive treatment fluid. As the reactive treatmentfluid is applied to (flows through) the wellbore, the esters mayhydrolyze over time to generate acid including due to temperature of thesubterranean formation or wellbore. The acid may lower the viscosity ofthe reactive treatment fluid (VES gel) and also dissolve the weightingagent (e.g., calcium carbonate) from the previously-applied drillingfluid in the filter cake. The esters can be, for example, of carboxylicacid. Fast degrading esters may be utilized for wellbores insubterranean formations having lower temperatures. In contrast, slowhydrolyzing esters may be utilized for wellbores in subterraneanformations having higher temperatures. The ester or esters may belabeled as acid-generating material in the reactive treatment fluid.

A third technique to generate acid in situ may be to add ammoniumsalt(s) to the reactive treatment fluid whereby excess oxidizing salt(such as bromate salts) in the reactive treatment fluid can oxidizeammonium to generate acid. The acid can lower the gel viscosity of thereactive treatment fluid and dissolve the weighting agent (e.g., calciumcarbonate) in the filter cake. The combination of the ammonium salt andthe oxidizing salt (e.g., bromate salt) may be labeled asacid-generating material in the reactive treatment fluid. The oxidizingsalt can be the same oxidizing salt as the aforementioned reactivebreaker. If so, the oxidizing salt in this acid generation may be excessoxidizing salt from the polymer breaking. This oxidizing salt may alsobe in excess to that needed to react with the ammonium for acidgeneration. The oxidizing salt can be different than the oxidizing saltthat is the reactive breaker. The oxidizing salt may be a secondoxidizing salt in addition to the oxidizing salt as the aforementionedreactive breaker that breaks the polymer in the filter cake. Regardingacid generation via ammonium oxidation, the anion of the ammonium saltmay dictate the acid formed such that ammonium citrate produces citricacid, ammonium sulfonate produces sulfonic acid, ammonium sulfateproduces sulfuric acid, etc. A wide variety of ammonium salts may besuitable for generating the acid. As non-limiting examples, see Examples7-8 below. The length of an induction time prior to acid being generatedmay be controlled by the counteranion with the ammonium salt or byaddition of nonoxidizing salts. In some embodiments, addition oflithium-based salts may delay the formation of acid. In someembodiments, addition of bromide-based salts may delay the formation ofacid.

The amount or concentration of acid-generating material (e.g., esters,degradable solid particles, etc.) to specify to include in the reactivetreatment fluid may be correlative with the amount or concentration ofthe weighting agent (e.g., calcium carbonate) in the filter cake. Thequantity of acid-generating material in the reactive treatment fluid maybe based on the amount of generated acid to dissolve most or all of theweighting agent in the filter cake. In certain embodiments, the amountof acid-generating material for the reactive treatment fluid may bespecified to generate an amount of acid that is in a range of 2 to 5times the amount of acid needed to dissolve all (or a majority) of theweighting agent (e.g., calcium carbonate) in the filter cake.Stoichiometry may be considered. The amount of acid-generating material(e.g., esters, degradable solid particles, etc.) to include in thereactive treatment fluid may be specified correlative with thecalculated stoichiometric amount of acid to dissolve most or all of theweighting agent (e.g., calcium carbonate) in the filter cake. Again, theamount or concentration of the acid-generating material incorporatedinto the reactive treatment fluid may be based at least in part on theamount or concentration of the weighting agent the filter cake. Therelationship may be a stoichiometric relationship based on thestoichiometry of the amount of generated acid to dissolve most or all ofthe weighting agent. In some implementations, the specified amount(concentration) of the acid generating material in the reactivetreatment fluid may generate acid in a range of 2 to 5 times thestoichiometric amount of acid needed to dissolve most or all of theweighting agent in the filter cake.

In particular embodiments, the reactive treatment fluid for treating(removing) filter cake may include an inverting surfactant that isencapsulated. The material that encapsulates the inverting surfactantmay be degradable. This degradable material encapsulating the invertingsurfactant may degrade at the wellbore temperature and therefore releasethe inverting surfactant. In implementations, the inverting surfactanthas a hydrophile-lipophile balance (HLB) of at least 12. The invertingsurfactant may be applicable for oil-based filter cake. The invertingsurfactant released may invert oil-based filter cake formed by oil-basedmud (oil-based drilling fluid). Such may promote breakage of oil-basedmud and filter cake. The encapsulated inverting surfactant can be addedto certain embodiments of the present reactive treatment fluid(VES-fluid).

EXAMPLES

The Examples are given only as examples and not meant to limit thepresent techniques. Example 3, Example 4, Example 5, Example 6, Example7, and Example 8 are presented. Additional Examples are presentedfurther below.

Example 3

Example 3 relates to an enhancement experiment #1 for filter cakepermeability. An OFITE filter press was utilized. The OFITE filter pressis available from OFI Testing Equipment, Inc. (OFITE) havingheadquarters in Houston, Tex., USA.

Drilling mud (drilling fluid) was prepared according to the followingprocedure. A mixer was utilized to combine 8 g KCl, 0.2 g sodiumhydroxide (NaOH), 0.2 g sodium carbonate (Na₂CO₃), and 6 g hydroxyethylcellulose. After mixing for 5 minutes, 1 g xanthan gum was added andmixed another minute. Then, 0.5 g sodium thiosulfate (NaS₂O₃), 0.5biocide, 20 g calcium carbonate (CaCO₃) (particle size about 5 μm), and20 g CaCO₃ (particle size about 20 μm) were added and mixed anotherminute. Defoamer was added dropwise as needed and mixed 30 more secondsto give the drilling mud.

An amount of 50 mL of the prepared drilling mud were placed in twoseparate cells of the OFITE filter press. A ceramic filter disc wasadded to each, and the cells were sealed and placed in the filter press.After heating to 150° F. for 1 hour, the back pressure was released andfluid at 1000 psig was allowed to pass through the filters producingsolid cakes composed of the slurry components.

The cells were cooled and reopened to remove the ceramic filter discs.In the first cell, 50 mL of VES gel composed of 7.5 vol % Armovis EHS®in aqueous saturated NaBrO₃ solution was added. In the second cell, 50mL of VES gel composed of 7.5 vol % Armovis EHS® in 10 wt % CaCl₂ wasadded. Armovis EHS® is zwitterionic surfactant that is an amphoteric VESavailable from Nouryon Company having headquarters in Amsterdam,Netherlands. The filter discs with filter cakes were placed back in thecell, and the cells were sealed and put back in the filter press. Eachcell was heated to 225° F. for 1 hour at 1000 psig. Then, the bottomvalve was opened to allow any filtrate to pass through. For VES withoxidizing salt, fluid passed through readily indicating that thepolymeric material in the filter cake had degraded. For the VES withnonoxidizing salt, no fluid pass through the filter. Visual inspectionof the filter cakes after removing them from the instrument confirmedthese conclusions. FIG. 18 is an image 1800 of the two filter cakes. Thefilter cake 1802 on the left is associated with the VES with CaCl₂. Thefluid generally did not pass through at 1000 psig. The final texture wasvery gooey from polymer inclusion. The filter cake 1804 on the right isthe associated with the VES with NaBrO₃ (oxidizer). The fluid broke downthe polymer and thus created permeability in the cake. The final texturewas a clean dry powder.

Example 4

Example 4 relates to an enhancement experiment #2 for filter cakepermeability. Drilling mud was prepared as in Example 3. Also as inExample 3, 50 mL of the prepared drilling mud were placed in twoseparate cells of the OFITE filter press. A ceramic filter disc wasadded to each, and the cells were sealed and placed in the filter press.After heating to 150° F. at 1000 psig for 1 hour, the back pressure wasreleased and fluid was allowed to pass through the filters producingsolid cakes composed of the slurry components. The cells were cooled andreopened to remove the ceramic filter discs. In the first cell, 50 mL ofVES gel composed of 7.5 vol % Armovis EHS® in aqueous saturated NaBrO₃solution was added. In the second cell, 50 mL of VES gel composed of 7.5vol % Armovis EHS® in 10 wt % CaCl₂ was added. The filter discs withfilter cakes were placed back in the cell, and the cells were sealed andput back in the filter press. Each cell was heated to 225° F. for 1 hourat 1000 psig, then the bottom valve was opened to allow any filtrate topass through. In this case, the filtrate was collected on a balance.Initially, approximately 7 g of the oxidizing VES passed through thefilter cake. After 40 more minutes, an additional 26 g of filtrate wascollected, while only about 6 g total was collected from the CaCl₂ VES.FIG. 19 is a plot 1900 of the filtrate (g) versus time in minutes. Thecurve 1902 is for the 10 wt % CaCl₂ solution (noted in the legend). Thecurve 1904 is for the saturated NaBrO₃ solution (noted in the legend).

Example 5

Example 5 relates to gel breaking experiments. Viscosity tests (at 200°F. and 100 s⁻¹) were performed with 5 wt % and 7.5 wt % Armovis EHS®(VES) in saturated NaBrO₃ solution at 200° F. Experiments were performedwith and without 2 wt % FP9515SH polymer (polymer), and with and without1.6 wt % ammonium chloride (NH₄Cl). The polymer enhanced the viscosityof the VES (as previously demonstrated), and the ammonium (NH₄ ⁺)cations were oxidized by bromate (BrO₃ ⁻) to produce hydrogen ions H⁺.The decrease in pH disrupted the micelles, causing the viscosity todrop. The acid produced will also further decompose the filter cake bydissolving the CaCO₃. Other NH₄ ⁺ salts are also applicable. FIG. 20 isa plot 200 of viscosity (cP) over time (minutes). The curve 2002 isviscosity (over time) for the solution having 5 wt % VES, 2 wt % polymerand 2 wt % NH₄C. The curve 2004 is viscosity (over time) for thesolution having 5 wt % VES and 2 wt % polymer. The curve 2006 isviscosity (over time) for the solution having 7.5 wt % VES and 2 wt %NH₄Cl. The curve 2008 is viscosity (over time) for the solution having7.5 wt % VES.

Example 6

Example 6 relates to additional viscosity tests. Five VES-based fluidswere prepared in order to determine the effect of various combinationsof salts (oxidizing and nonoxidizing) on the viscosity of 8% ArmovisEHS® solutions at various temperatures. The conditions for all five ofthe fluids are given in Table 3 below. The fluids were prepared by firstdissolving the salt(s) in the volume of water listed in Table 3. Then,the VES was added and the solution agitated to ensure good mixing. FIG.21 is a plot 2100 of viscosity (cP) over time (minutes) for the fivefluids given in Table 3. The curves 2102, 2104, 2106, 2108, and 2110 inthe plot 2100 are for the fluid samples 1, 2, 3, 4, and 5, respectively.The curve 2112 is temperature (° F.).

TABLE 3 Solution parameters for five VES fluids for viscositymeasurements Water VES KCl KCl CaCl₂ · 2H₂O CaCl₂ NaBrO₃ NaBrO₃ Totalion Sample (mL) (mL) (g) (m) (g) (m) (g) (m) molality 1 130 12 0 0 100.45 0 0 1.34 2 130 12 0 0 7.5 0.34 3.75 0.166 1.35 3 130 12 0 0 0 015.3 0.677 1.35 4 130 12 7.5 0.67 0 0 0 0 1.34 5 130 12 5.7 0.51 0 03.75 0.166 1.34

Example 7

Example 7 is an example of generating in situ acid. Example 7 includesan implementation of the aforementioned third technique of generating anacid via a combination of an ammonium salt (e.g., NH₄CF₃SO₃) andoxidizing salt (e.g., NaBrO₃) that react with each other. In thisexample, 1.6 g of NaBrO₃ (10.6 mmol) and 1.67 g NH₄CF₃SO₃ (10 mmol) wasdissolved in 27 mL of deionized water in a 120 mL Ace glass pressuretube. Then, 2.4 mL of Armovis EHS® was added, and the mixture wascombined. The glass tube was sealed and placed in a recirculating oilbath at 100° C. for 24 hours. After cooling, the fluid pH was 1.23 andwas titrated with NaOH revealing that 8.4 mmol of H⁺ had been generated.

Example 8

Example 8 is another example of generating in situ acid. Example 8 alsoincludes an implementation of the aforementioned third technique ofgenerating an acid via a combination of an ammonium salt (e.g.,NH₄CF₃SO₃) and oxidizing salt (e.g., NaBrO₃) that react with each other.In this example, 1.6 g of NaBrO₃ (10.6 mmol) and 1.31 g NH₄CF₃CO₂ (10mmol) was dissolved in 27 mL of deionized water in a 120 mL Ace glasspressure tube. Then, 2.4 mL of ArmoVis EHS was added, and the mixturewas combined. The glass tube was sealed and placed in a recirculatingoil bath at 100° C. for 24 hours. After cooling, the fluid pH was 1.24and was titrated with NaOH revealing that 8.3 mmol of H⁺ had beengenerated.

VES surfactant can be gelled with oxidizing brine solutions. The gelstrength may be comparable to that implemented with potassium chlorideor calcium chloride. The filter cake breaking tests demonstratedpositive results. The techniques may specify concentrations for desiredgel profile, specify and expand temperature range of applications, andcorrelate applications with filter cake breaking tests under variableconditions.

Example 9

Example 9 were viscosity tests (in situ acid formed). Five VES-basedfluids were prepared in order to determine the effect of variouscombinations of salts on the viscosity of 8 vol % Armovis EHS solutionsat various temperatures. Each fluid contained both oxidizing salt and anammonium salt capable of forming in situ acid. The conditions for allfive of the fluids are listed in Table 4 below. The fluids were preparedby first dissolving the salt(s) in the volume of water listed in Table4. Then, the VES was added and the solution agitated to ensure goodmixing.

TABLE 4 Solution parameters for five VES fluids for viscositymeasurements Water VES Fluid (mL) (mL) NaBrO₃ (g) NH₄X (g) X⁻ 1 65 6 4.01.93 acetate 2 65 6 4.0 1.58 formate 3 65 6 4.0 1.33 chloride 4 65 6 4.02.45 bromide 5 65 6 4.0 2.83 MSA

FIG. 22 is a plot 2200 of viscosity (cP) over time (minutes) for thefive fluids given in Table 4. The curves 2202, 2204, 2206, 2208, and2210 in the plot 2200 are for the fluid samples 1, 2, 3, 4, and 5,respectively. The curve 2212 is temperature (° F.).

Example 10

Drilling mud (drilling fluid) was prepared according to the followingprocedure. A mixer was used to combine 8 g KCl, 0.2 g NaOH, 0.2 gNa₂CO₃, and 6 g hydroxyethyl cellulose. After mixing for 5 minutes, 1 gxanthan gum was added and mixed another minute. 0.5 g NaS₂O₃, 0.5biocide, 20 g CaCO₃ (5 μm), and 20 g CaCO₃ (20 μm) were added and mixedanother minute. Defoamer was added dropwise as needed and mixed 30 moreseconds.

A volume of 35 mL of the prepared drilling mud was placed in each of thefour cells of an OFITE filter press. A ceramic filter disc was added toeach cell, and the cells were sealed and placed in the filter press. Thecells were heated to 250° F. at 700 psig, and the bottom valve wasopened to allow fluid to pass through the filters producing solid cakescomposed of the slurry components. The filtrate was collected on abalance, and the results of the filter cake deposition are depicted inFIG. 23.

FIG. 23 is a plot 2300 of volume in cubic centimeters (cc) (or mL) ofthe filtrate collected as the filter cake was deposited versus timegiven in time notation 00:00:00 of hour, minutes, and seconds. The fourcurves 2302, 2304, 2306, and 2308 are for the filtrate collected as thefour filter cakes were formed in the four cells, respectively. As can beseen, the four curves are close to each other.

The cells were then cooled and opened to remove the ceramic filterdiscs. In each cell, 50 mL of VES gel-based treatment fluids 1, 2, 3,and 4 have the formulations in Table 5 below was added to the fourcells, respectively.

TABLE 5 VES gel-based treatment fluids for Example 10 Water VES Fluid(mL) (mL) NaBrO₃ (g) NH₄X (g) X⁻ 1 130 12 8.0 4.90 bromide 2 130 12 8.03.15 formate 3 130 12 8.0 2.65 chloride 4 130 12 8.0 3.85 acetate

The filter discs with filter cakes were placed back in the cell, and thecells were sealed and put back in the filter press. Each cell was heatedto 250° F. at 700 psig, and then the bottom valve was opened to allowany filtrate to pass through. The filtrate was collected on a balance,and the results are depicted in FIG. 24. Fluid breakthrough occurredrelatively quickly due to the formation of acid at this temperature.FIG. 24 is a plot 2400 of volume (cc) of the filtrate breakthroughcollected through the already-deposited filter cakes versus time givenin time notation 00:00:00 of hour, minutes, and seconds. The threecurves 2402, 2404, and 2406 are for the treatments of the second, third,and fourth already-deposited filter cakes (deposited as indicated by2304, 2306, and 2308 of FIG. 23) with fluids 2, 3, and 4 of Table 4,respectively.

Example 11

Example 11 is directed to filter cake permeability enhancement. Drillingmud was prepared according to the following procedure. A mixer was usedto combine 8 g KCl, 0.2 g NaOH, 0.2 g Na₂CO₃, and 6 g hydroxyethylcellulose. After mixing for 5 minutes, 1 g xanthan gum was added andmixed another minute. Then, 0.5 g NaS₂O₃, 0.5 biocide, 20 g CaCO₃ (5μm), and 20 g CaCO₃ (20 μm) were added and mixed another minute.Defoamer was added dropwise as needed and mixed 30 more seconds.

A volume of 75 mL of the prepared drilling mud were placed in each ofthe four cells of an OFITE filter press. A ceramic filter disc was addedto each cell, and the cells were sealed and placed in the filter press.The cells were heated to 200° F. at 700 psig, and the bottom valve wasopened to allow fluid to pass through the filters producing solid cakescomposed of the slurry components. The filtrate was collected on abalance, and the results of the filter cake deposition are depicted inFIG. 25. Each filter cake was deposited for different lengths of time inorder to form variable thicknesses. Again, results are given in FIG. 25.FIG. 25 is a plot 2500 of volume (cc) of the filtrate collected as thefilter cake was deposited versus time given in time notation 00:00:00 ofhour, minutes, and seconds. The four curves 2502, 2504, 2506, and 2508are for the filtrate collected as the four filter cakes were formed inthe four cells, respectively. The curve 2502 is for 10 mL filtrate andthen the deposition stopped. Curve 2504 is for 20 mL filtrate collectedand then the deposition of that filter cake stopped. Curve 2506 is for50 mL filtrate collected and then the deposition of that filter cakestopped. Curve 2508 is also for 50 mL filtrate collected and then thedeposition of that filter cake stopped.

The cells were cooled and opened to remove the ceramic filter discs. Ineach cell, 50 mL of VES gel containing 8.0 g NaBrO₃, 3.15 g ammoniumformate, 130 mL water, and 12 mL Armovis-EHS were added. The filterdiscs with filter cakes were placed back in the cell, and the cells weresealed and put back in the filter press. Each cell was heated to 200° F.at 700 psig, and then the bottom valve was opened to allow filtrate topass through. The filtrate was collected on a balance, and the resultsare depicted in FIG. 26. FIG. 26 is a plot 2600 of volume (cc) of thefiltrate breakthrough collected through the already-deposited filtercake versus time given in time notation 00:00:00 of hour, minutes, andseconds. The four curves 2602, 2604, 2606, and 2608 are respectively forthe treatments of the filter cakes that were deposited at 10 mLfiltrate, 20 mL filtrate, 50 mL filtrate-1, and 50 mL filtrate-2 asdiscussed with respect to FIG. 25.

Example 12

Example 12 is directed to filter cake permeability enhancement. Drillingmud was prepared according to the following procedure. A mixer was usedto combine 8 g KCl, 0.2 g NaOH, 0.2 g Na₂CO₃, and 6 g hydroxyethylcellulose. After mixing for 5 minutes, 1 g xanthan gum was added andmixed another minute. 0.5 g NaS₂O₃, 0.5 biocide, 20 g CaCO₃ (5 μm), and20 g CaCO₃ (20 μm) were added and mixed another minute. Defoamer wasadded dropwise as needed and mixed 30 more seconds.

Variable quantities of drilling mud were placed in each of the fourcells, respectively, of an OFITE filter press in order to form variablethicknesses of filter cake. The quantities of drilling mud were 20 mL(cell 1), 35 mL (cell 2), 55 mL (cell 3), 75 mL (cell 4). A ceramicfilter disc was added to each cell, and the cells were sealed and placedin the filter press. The cells were heated to 200° F. at 700 psig, andthe bottom valve was opened to allow fluid to pass through the filtersproducing solid cakes composed of the slurry components. The filtratewas collected on a balance, and the results of the filter cakedeposition are depicted in FIG. 27.

FIG. 27 is a plot 2700 of volume (cc) of the filtrate collected as thefilter cake was deposited versus time given in time notation 00:00:00 ofhour, minutes, and seconds. The four curves 2702, 2704, 2706, and 2708are for the filtrate collected as the four filter cakes were formed inthe four cells, respectively. The curve 2702 is for 20 mL of drillingmud used in cell 1. Curve 2704 is for 35 mL drilling mud used in cell 2.Curve 2706 is for 55 mL drilling mud used in cell 3. Curve 2708 is for75 mL filtrate used in cell 4.

To each of the four cells, 50 mL of VES gel containing 8.0 g NaBrO₃,3.15 g ammonium formate, 130 mL water, and 12 mL Armovis-EHS were addedvia a pump. The bottom valve was opened to allow filtrate to passthrough. The filtrate was collected on a balance, and the results areplotted in FIG. 28. FIG. 28 is a plot 2800 of volume (cc) of thefiltrate breakthrough collected through the already-deposited filtercake versus time given in time notation 00:00:00 of hour, minutes, andseconds. The four curves 2802, 2804, 2806, and 2808 are respectively forthe treatments of the filter cakes that were deposited at 120 mLdrilling mud (cell 1), 35 mL drilling mud (cell 2), 55 mL drilling mud(cell 3), and 75 mL drilling mud (cell 4) as discussed with respect toFIG. 27.

Example 13

Example 13 is directed to filter cake permeability enhancement. Drillingmud was prepared according to the following procedure. A mixer was usedto combine 8 g KCl, 0.2 g NaOH, 0.2 g Na₂CO₃, and 6 g hydroxyethylcellulose. After mixing for 5 minutes, 1 g xanthan gum was added andmixed another minute. Then, 0.5 g NaS₂O₃, 0.5 biocide, 20 g CaCO₃ (5μm), and 20 g CaCO₃ (20 μm) were added and mixed another minute.Defoamer was added dropwise as needed and mixed 30 more seconds.

To each of the four cells of an OFITE filter press, 35 mL of thedrilling mud was added. A ceramic filter disc was added to each cell,and the cells were sealed and placed in the filter press. The cells wereheated to 200° F. at 700 psig, and the bottom valve was opened to allowfluid to pass through the filters producing solid cakes composed of theslurry components. The filtrate was collected on a balance. The resultsof the filter cake deposition are given in FIG. 29. FIG. 29 is a plot2900 of volume (cc) of the filtrate collected as the filter cake wasdeposited versus time given in time notation 00:00:00 of hour, minutes,and seconds. The four curves 2902, 2904, 2906, and 2908 are for thefiltrate collected as the four filter cakes were formed in the fourcells, respectively.

To each of the four cells, 50 mL of VES fluid was then added via pump.The formulations for each of the fluids were varied by addingnonoxidizing salts—either LiBr or CaBr₂. The formulations of the fourVES fluids tested are given in Table 6.

TABLE 6 VES treatment fluids for Example 13 Water VES Salt NaBrO₃ NH₄XFluid (mL) (mL) Salt (g) (g) (g) X⁻ 1 130 12 LiBr 3.47 6.0 3.15 formate2 130 12 CaBr₂ 5.33 6.0 3.15 formate 3 130 12 LiBr 1.15 6.0 3.15 formate4 130 12 CaBr₂ 1.77 6.0 3.15 formate

The bottom valve was opened to allow filtrate to pass through. Thefiltrate was collected on a balance. The results are given in FIG. 30.FIG. 30 is a plot 3000 of volume (cc) of the filtrate breakthroughcollected through the already-deposited filter cake versus time given intime notation 00:00:00 of hour, minutes, and seconds. The curve 3002 isfor treatment of the filter cake in cell 1 with the fluid 1. Curve 3004is for the treatment of the filter cake in cell 2 with the fluid 2.Curve 3006 is for the treatment of the filter cake in cell 3 with thefluid 3. Curve 3008 is for the treatment of the filter cake in cell 4with the fluid 4.

Example 14

Example 14 is directed to in situ acid generation experiments utilizingdelay agents. In the experiments, an aqueous-based salt solution wasprepared in a 120 mL transparent Ace Glass pressure tube by combiningNH₄X, NaBrO₃ and DI-H₂O (25 mL). Here, X is methanesulfonate (MS) orchloride (Cl). Each colorless solution was sealed and heated in apre-heated recirculating silicone oil bath at 150° C. under ambientpressure conditions. The induction period leading to acid generation wascarefully monitored via visual inspection as evident by a change in thesolution from colorless to orange. This is a signature for the evolutionof bromine (Br₂) gas, a side-product of this reaction. All solutionswere cooled to room temperature and acid-base titration measurementsperformed to determine the resultant acid concentration (mmol).Furthermore, a series of alkali salts (up to 50 mmol LiCl or LiBr) wereindependently added to the aforementioned ammonium-based systems and theinduction times and acid concentration compared to the baseline system.The addition of LiBr to either the NH₄Cl or NH₄MS system caused asignificant increase in the induction time, thus delaying acidgeneration. LiCl, however, did not exhibit this effect but rather showeda decrease in the induction time.

FIGS. 31 and 32 are plots showing the results of combining 10 mmolNH₄Cl, 5 mmol NaBrO₃, and either LiCl or LiBr, respectively. WithoutLiCl or LiBr, the induction time for acid generation is 10 minutes. FIG.31 is a plot of induction time 3100 (minutes) versus concentration ofLiBr (mmol). The smaller dots 3100 are induction time. The larger dots3102 are concentration of hydrogen ions H+. FIG. 32 is a plot ofinduction time 3200 (minutes) versus concentration of LiCl (mmol). Thesmaller dots 3200 are induction time. The larger dots 3202 areconcentration of hydrogen ions H+.

FIGS. 33 and 34 are plots showing the results of combining 10 mmolNH₄MS, 5 mmol NaBrO₃, and either LiCl or LiBr, respectively. WithoutLiCl or LiBr, the induction time for acid generation is 45 minutes. FIG.33 is a plot of induction time 3300 (minutes) versus concentration ofLiBr (mmol). The smaller dots 3300 are induction time. The larger dots3302 are concentration of hydrogen ions H+. FIG. 34 is a plot ofinduction time 3400 (minutes) versus concentration of LiCl (mmol). Thesmaller dots 3400 are induction time. The larger dots 3402 areconcentration of hydrogen ions H+.

An embodiment is a method of treating a wellbore for filter cakeremoval, including providing a reactive treatment fluid having VES intoa wellbore in a subterranean formation to attack filter cake in thewellbore, and attacking (e.g., degrading, dissolving, removing, etc.)the filter cake via the reactive treatment fluid. The filter cake may beformed from solids in drilling fluid. The method may include removing atleast a portion of the filter cake from the wellbore via the attackingof the filter cake with the reactive treatment fluid. The reactivetreatment fluid have a reactive breaker including an oxidizing salt. Insome implementations, the oxidizing salt is at a concentration of atleast 22 wt % in the reactive treatment fluid. The filter cake mayinclude polymer, and wherein the reactive breaker breaks the polymer. Incertain implementations, the oxidizing salt is at a concentration in thereactive treatment fluid in excess of that needed to break the polymerin the filter cake. The reactive treatment fluid may be a VES gel,wherein gelling performance of the VES gel promotes retention of theoxidizing salt in the reactive treatment fluid for breaking the polymerin the filter cake at an end portion of a lateral of a horizontalportion of the wellbore.

The reactive treatment fluid (e.g., VES gel) may include anacid-generating material to facilitate attacking the filter cake in thewellbore, wherein attacking the filter cake involves forming acid fromthe acid-generating material and attacking the filter cake with theacid, and wherein forming the acid may lower viscosity of the VES gel.The filter cake may include a weighting agent from a drilling fluid, andwherein attacking the filter cake involves dissolving the weightingagent via the acid. The weighting agent may be, for example, calciumcarbonate, barite, bentonite, ilmenite, or manganese tetroxide, or anycombinations thereof. Forming the acid may involve releasing the acidfrom the acid-generating material. In some implementations, the acid ishydrochloric acid. The forming of the acid may involve releasinghydrogen ions or hydrogen chloride from the acid-generating material. Inimplementations, the acid-generating material is neutral in the reactivetreatment fluid at Earth surface prior to providing the reactivetreatment fluid into the wellbore. The forming of the acid may involveforming the acid from the acid-generating material via heat from thesubterranean formation. The forming of the acid may involve releasingthe acid from the acid-generating material, wherein the acid-generatingmaterial includes solid particles that degrade in the wellbore due totemperature of the subterranean formation to release the acid, andwherein particle size of the solid particles may be in a range, forexample, of 20 microns to 2 mm. The acid-generating material includingthe solid particles may be, for example, PLA, PGA, an orthoester, orpolyanhydride, or any combinations thereof. The acid-generating materialmay be an ester (e.g., of a carboxylic acid), and wherein forming theacid comprises hydrolyzing the ester to generate the acid. Theacid-generating material may be a combination of ammonium salt and anoxidizing salt (e.g., including bromate), and wherein forming the acidcomprises oxidizing ammonium of the ammonium salt with the oxidizingsalt.

The reactive treatment fluid may include an inverting surfactantencapsulated in an encapsulating material that degrades at temperatureof the wellbore or subterranean formation, and wherein the filter cakeincludes an oil-based filter cake formed from oil-based drilling fluid.The method may include degrading the encapsulating material to releasethe inverting surfactant, and inverting the oil-based filter cake withthe inverting surfactant, wherein the inverting surfactant may have ahydrophile-lipophile balance (HLB) of at least 12.

Another embodiment is a reactive treatment fluid (e.g., VES gel) forremoving filter cake from a wellbore in a subterranean formation. Thereactive treatment fluid has a reactive breaker including an oxidizingsalt to break polymer in the filter cake. The reactive treatment fluidmay have the oxidizing salt, for example, at a concentration of at least22 wt % in certain implementations. In implementations, the oxidizingsalt does generally does not break the VES gel. The reactive treatmentfluid includes VES to gel the reactive treatment fluid to give thereactive treatment fluid as a VES gel (e.g., for retention of theoxidizing salt for breaking the polymer in the filter cake at an endportion of a lateral of the wellbore). The reactive treatment fluidincludes an acid-generating material to form acid (e.g., hydrochloricacid) via heat from the subterranean formation to attack weighting agentfrom drilling fluid in the filter cake, wherein the acid lowersviscosity of the VES gel and may dissolve the weighting agent in thefilter cake. In certain implementations, the acid-generating materialmay include degradable solid particles (e.g., particle size in range of20 μm to 2 mm) that degrade in the wellbore due to temperature of thesubterranean formation or wellbore to form the acid. The acid-generatingmaterial including the solid particles may be, for example, PLA, PGA, anorthoester, or polyanhydride, or any combinations thereof. Theacid-generating material may be an ester (e.g., of a carboxylic acid)that hydrolyzes to form the acid. The acid-generating material may be acombination of ammonium salt and a second oxidizing salt (e.g.,bromate), and wherein ammonium of the ammonium salt is oxidized by thesecond oxidizing salt to form the acid. The acid-generating material maybe neutral in the reactive treatment fluid at Earth surface prior tointroduction of the reactive treatment fluid into the wellbore. Lastly,the reactive treatment fluid may include an inverting surfactantencapsulated in an encapsulating material that degrades at temperatureof the subterranean formation or wellbore, and wherein the filter cakeincludes an oil-based filter cake formed from oil-based drilling fluid.In those implementations, the inverting surfactant may invert theoil-based filter cake, wherein the inverting surfactant may have an HLBof at least 12.

Below is a discussion of ammonium salts that may be employed in theaforementioned third technique to generate acid in situ in whichammonium salt(s) are added to the reactive treatment fluid wherebyoxidizing salt (such as bromate salts) in the reactive treatment fluidcan oxidize ammonium to generate hydrogen ions and acid. In thiscontext, the ammonium salts described below may be sources of hydrogenions for generating acids. The ammonium salt may be or includes anammonium halide. The ammonium halide may be or include, for example,ammonium fluoride, ammonium chloride, ammonium bromide, ammonium iodide,and mixtures thereof. The ammonium salt can be or include ammoniumfluoride, hydrogen difluoride, ammonium chloride, etc. The ammonium saltcan include an anion that is also an oxidizing agent. For instance, insome embodiments, an ammonium salt includes ammonium persulfate. In someimplementations, the ammonium salt includes a polyatomic anion such assulfate, hydrogen sulfate, thiosulfate, nitrite, nitrate, phosphite,phosphate, monohydrogen phosphate, dihydrogen phosphate, carbonate, andcombinations thereof. Other such polyatomic anions are known to those ofskill in the chemical arts. For example, as described in Wade, L. G. Jr.(2005) Organic Chemistry (6th Edition) Prentice Hall. In someembodiments, an ammonium salt includes an oxidation-resistant anion. Aperson of skilled in the art would understand what ammonium salts areuseful or desired for reaction with a particular oxidizing agentdepending on the strength of the acid desired. In some embodiments, anammonium salt is an N-substituted ammonium salt, which may bemono-substituted or di-substituted, for instance with one or two alkylgroups, or is tri-substituted, for instance with three alkyl groups.Exemplary alkyl groups include methyl, ethyl, propyl, butyl, and thelike. In some embodiments, an ammonium salt is not a tri-substitutedammonium salt or is not a tetra-substituted ammonium salt. In someimplementations, an ammonium salt is selected based on an intendedapplication. A person of skill in the art, looking to prepare describedcompositions, will appreciate that various ammonium salts are beneficialfor use in delivering certain acids applicable to attacking or removingthe particular filter-cake composition.

In implementations, the selected ammonium salts can include ammoniumalkylsulfonates, ammonium arylsulfonates, ammonium alkarylsulfonates, orany combinations thereof. In some embodiments, an ammonium salt isselected from substituted and unsubstituted ammonium alkylsulfonates,ammonium arylsulfonates, and combinations thereof. In implementations,an alkyl group of an alkylsulfonate anion can be substituted with one ormore of halogen, —OR, and —SR, wherein R is hydrogen or a C1-6 alkyl. Insome embodiments, an ammonium salt is selected from ammoniummethanesulfonate, ammonium ethanesulfonate, ammonium propanesulfonate,ammonium butanesulfonate, ammonium trifluoromethanesulfonate, ammoniumperfluorobutanesulfonate, ammonium chlorobenzenesulfonate, ammoniump-iodobenzenesulfonate, ammonium benzenesulfonate, ammoniump-toluenesulfonate, ammonium camphorsulfonate, and combinations thereof.In certain embodiments, an ammonium salt is selected from ammoniummethanesulfonate, ammonium trifluoromethanesulfonate, and ammoniumperfluorobutanesulfonate. In embodiments, an ammonium salt may beselected based on an intended application. A person of skill in the art,looking to prepare described compositions, will appreciate that variousammonium salts are suitable for use in delivering certain acids.Encompassed in the present disclosure is the recognition thatsulfonate-based ammonium salts exhibit, in some embodiments, improvedcontrol over acid generation. Such improvement is a prolonged inductiontime for acid generation. That is, there is an increased delay of acidgeneration in situ when a selected ammonium salt is a sulfonate-basedammonium salt. For instance, an intended application may be that itdesirable to deliver an organic acid, for example methanesulfonic acid,to a zone of interest in a delayed fashion. For example, in someembodiments, ammonium methanesulfonate is selected as an ammonium salt.In particular embodiments an intended application may be that itdesirable to generate a super acid, for example trifluoromethanesulfonicacid or triflic acid. In implementations, ammoniumtrifluoromethanesulfonate is selected as an ammonium salt. In someembodiments, where prolonged durations of time are needed to generateacid, a sulfonate-based ammonium salt having a higher degree ofhydrophobicity can be employed. For example, in some embodiments,ammonium perfluorobutanesulfonate is selected as an ammonium salt.Lastly, in implementations, the ammonium salt may be composed of anionsof formate, citrate, oxalate, ascorbate, acetate, trifluoroacetate, andother carboxylates.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made without departingfrom the spirit and scope of the disclosure.

What is claimed is:
 1. A method of treating a wellbore for filter cakeremoval, comprising: providing a reactive treatment fluid comprising aviscoelastic surfactant (VES) into a wellbore in a subterraneanformation to attack filter cake in the wellbore, wherein the reactivetreatment fluid comprises: a reactive breaker comprising an oxidizingsalt; and an acid-generating material; and attacking the filter cake viathe reactive treatment fluid, wherein attacking the filter cake via thereactive treatment fluid comprises forming acid from the acid-generatingmaterial and attacking the filter cake with the acid.
 2. The method ofclaim 1, wherein the filter cake is formed from solids in drillingfluid, and wherein attacking the filter cake comprises degrading thefilter cake or dissolving at least a portion of the filter cake, or acombination thereof.
 3. The method of claim 1, comprising delayingforming the acid from the acid-generating material in the wellbore, andwherein attacking the filter cake via the reactive treatment fluidcomprises attacking the filter cake with the reactive breaker comprisingthe oxidizing salt.
 4. The method of claim 1, comprising: specifyingthat the treatment fluid include the VES in response to the wellborecomprising a lateral, wherein the filter cake comprises polymer, andwherein the reactive breaker breaks the polymer; gelling the reactivetreatment fluid via the VES to give the reactive treatment fluid as aVES gel for retention of the oxidizing salt for breaking the polymer inthe filter cake at an end portion of the lateral; and flowing thereactive treatment fluid to the end portion of the lateral, whereinattacking the filter cake comprises breaking, via the oxidizing salt,the polymer in the filter cake at the end portion.
 5. The method ofclaim 1, comprising: specifying inclusion of the VES in the reactivetreatment fluid in response to the wellbore comprising a horizontalportion, wherein the reactive treatment fluid comprises a VES gel,wherein the filter cake comprises polymer, and wherein the reactivebreaker breaks the polymer; and flowing the reactive treatment fluidinto the horizontal portion, wherein gelling performance of the VES gelpromotes retention of the oxidizing salt in the reactive treatment fluidfor breaking the polymer in the filter cake at an end portion of alateral of the horizontal portion of the wellbore.
 6. The method ofclaim 1, wherein the filter cake comprises a weighting agent from adrilling fluid, and wherein attacking the filter cake comprisesdissolving the weighting agent with the acid.
 7. The method of claim 6,wherein the reactive treatment fluid comprises a VES gel, and whereinforming the acid lowers viscosity of the VES gel.
 8. The method of claim6, comprising specifying an amount of the acid generating material inthe reactive treatment fluid to generate acid in a range of 2 to 5 timesa stoichiometric amount of acid in relation to the weighting agent fordissolving substantially all of the weighting agent in the filter cake,wherein the weighting agent comprises calcium carbonate, bentonite,barite, ilmenite, or manganese tetroxide, or any combinations thereof.9. The method of claim 6, wherein forming the acid comprises forming theacid from the acid-generating material via heat from the subterraneanformation.
 10. The method of claim 6, wherein forming the acid comprisesreleasing the acid from the acid-generating material, wherein theacid-generating material comprises solid particles that degrade in thewellbore due to temperature of the subterranean formation to release theacid, and wherein particle size of the solid particles is in a range of20 microns to 2 millimeters (mm).
 11. The method of claim 10, whereinthe acid-generating material comprising the solid particles comprisepolylactic acid (PLA), poyglycolic acid (PGA), an orthoester, orpolyanhydride, or any combinations thereof.
 12. The method of claim 11,wherein the solid particles comprises polylactic acid (PLA) orpoyglycolic acid (PGA), or both.
 13. The method of claim 6, wherein theacid-generating material comprises an ester, and wherein forming theacid comprises hydrolyzing the ester to generate the acid.
 14. Themethod of claim 6, wherein the acid-generating material does notcomprise an ester that hydrolyzes to generate the acid, and wherein theacid-generating material does not comprise a polyanhydride.
 15. Themethod of claim 6, wherein the acid-generating material comprises acombination of ammonium salt and the oxidizing salt, and wherein formingthe acid comprises oxidizing ammonium of the ammonium salt with theoxidizing salt.
 16. The method of claim 15, wherein attacking the filtercake comprises breaking polymer in the filter cake with the oxidizingsalt, and wherein the reactive treatment fluid comprises the oxidizingsalt at a concentration in excess of that to break the polymer.
 17. Themethod of claim 16, wherein the oxidizing salt comprises bromate, andwherein the ammonium salt comprises a sulfonate-based ammonium salt orammonium chloride, or both.
 18. The method of claim 17, wherein thereactive treatment fluid comprises a lithium-based salt or abromide-based salt, or combination thereof, as a delay agent causing anincrease in induction time of acid generation by the acid-generatingmaterial that forms the acid.
 19. The method of claim 18, comprisingremoving at least a portion of the filter cake from the wellbore via theattacking of the filter cake with the reactive treatment fluid, whereinthe delay agent comprises lithium bromide (LiBr).
 20. The method ofclaim 6, wherein forming the acid comprises releasing the acid from theacid-generating material.
 21. The method of claim 6, wherein the formingthe acid comprises releasing hydrogen ions (W) from the acid-generatingmaterial.
 22. The method of claim 6, wherein the acid-generatingmaterial is neutral in the reactive treatment fluid at Earth surfaceprior to providing the reactive treatment fluid into the wellbore. 23.The method of claim 1, wherein the reactive treatment fluid comprises aninverting surfactant encapsulated in an encapsulating material thatdegrades at temperature of the subterranean formation, and wherein thefilter cake comprises an oil-based filter cake formed from oil-baseddrilling fluid.
 24. The method of claim 23, comprising: degrading theencapsulating material to release the inverting surfactant; andinverting the oil-based filter cake with the inverting surfactant,wherein the inverting surfactant comprises an hydrophile-lipophilebalance (HLB) of at least
 12. 25. A method of treating a wellbore forfilter cake removal, comprising: providing a reactive treatment fluidinto a wellbore in a subterranean formation to attack filter cake in thewellbore, wherein the reactive treatment fluid comprises: a reactivebreaker comprising an oxidizing salt to break polymer in the filtercake; a viscoelastic surfactant (VES) to gel the reactive treatmentfluid to give the reactive treatment fluid as a VES gel for retention ofthe oxidizing salt for breaking the polymer in the filter cake at an endportion of a lateral of the wellbore; and an acid-generating material toform acid to dissolve a weighting agent from drilling fluid in thefilter cake; flowing the reactive treatment fluid to the end portion ofthe lateral; gelling the reactive treatment fluid as the VES gel,thereby promoting retaining of the oxidizing salt in the reactivetreatment fluid to the end portion of the lateral; forming the acid viathe acid-generating material; and attacking the filter cake with thereactive treatment fluid.
 26. The method of claim 25, comprisingspecifying an amount of the acid generating material in the reactivetreatment fluid to generate acid in a range of 2 to 5 times astoichiometric amount of acid in relation to the weighting agent fordissolving substantially all of the weighting agent in the filter cake.27. The method of claim 25, comprising specifying that the treatmentfluid include the VES in response to the wellbore comprising thelateral, wherein attacking the filter cake with the reactive treatmentfluid comprises degrading the filter cake, dissolving the filter cake,or removing the filter cake, or any combinations thereof.
 28. The methodof claim 25, wherein attacking the filter cake with the reactivetreatment fluid comprises: breaking the polymer in the filter cake withthe oxidizing salt including at the end portion of the lateral; anddissolving the weighting agent in the filter cake with the acid.
 29. Themethod of claim 28, wherein the acid-generating material comprises solidparticles comprising polylactic acid (PLA) or poyglycolic acid (PGA), orboth, or wherein the acid-generating material comprises a combination ofammonium salt and a second oxidizing salt that oxidizes the ammonium ofthe ammonium salt to form the acid.
 30. The method of claim 29, whereinthe acid-generating material comprises the combination of the ammoniumsalt and the second oxidizing salt, wherein the second oxidizing saltcomprises the oxidizing salt that breaks the polymer, and wherein thereactive treatment fluid comprises the oxidizing salt at a concentrationin excess of that to break the polymer.
 31. The method of claim 29,wherein the acid-generating material comprises the combination of theammonium salt and the second oxidizing salt, wherein the ammonium saltcomprises a sulfonate-based ammonium salt or ammonium chloride, or both.32. The method of claim 31, wherein the reactive treatment fluidcomprises a lithium-based salt or a bromide-based salt, or a combinationthereof, as a delay agent causing an increase in induction time of acidgeneration by the acid-generating material that forms the acid.
 33. Themethod of claim 32, wherein the delay agent comprises lithium bromide(LiBr).